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EPA 
 Documentation Supplement for 

EPA Base Case v.4.10_FTransport – 

Updates for Final Transport Rule

U.S. Environmental Protection Agency 

Clean Air Markets Division 

1200 Pennsylvania Avenue, NW (6204J) 

Washington, D.C. 20460 

(www.epa.gov/airmarkets) 

June 2011 
Table of Contents

Introduction ....................................................................................................................................... 1 

Universal Comments Resulting in Model Revisions

1 Cogeneration Units ....................................................................................................................... 2 

2 NOx Rates ................................................................................................................................... 35 

3 SO2 Removal Rates for Flue Gas Desulfurization (FGD) ........................................................... 41 

4 Coal Switching − Bituminous to Subbituminous ......................................................................... 44 

5 Restrictions on coal choice in 2012 ............................................................................................ 46 

6 Waste Coal Cost Correction ....................................................................................................... 48 

7 Comments Considered but that did not Result in Changes ....................................................... 51 

• Oil consumption at dual fired (oil/gas) units 

• Capital cost of Flue Gas Desulfurization (FGD) on units whose capacity is less than 100 MW 

• Selective Catalytic Reduction (SCR) retrofit costs 

• 30 year book life for emission control retrofits 

• Must run, black start, and spinning reserve units 

• Availability assumptions for existing coal units 

Addenda: Notes on various modeling assumptions...................................................................... 53 

• Dry Sorbent Injection (DSI) and Fabric Filter Cost Development 

• Variable Operating and Maintenance (VOM) Cost of Dry Sorbent Injection (DSI) Retrofits 

• Updated Appendices 3-2 through 3-4 

• 2012 Emission Control Retrofits 

• Emission Controls in IPM Parsed Files 

• Mercury Emission Modification Factor (EMF) for Waste Coal Units 

• Carbon dioxide (CO2) Emissions from Chemical Reactions in a Wet Flue Gas Desulfurization 

(FGD) System for Sulfur Dioxide (SO2) Control 

Addendum A ─ Dry Sorbent Injection (DSI) and Fabric Filter Cost Development in EPA Base Case 

v.4.10_FTransport .......................................................................................................................... 55 

Addendum B ─ Representation of State Electric Power Emission Regulations (Appendix 3-2), New 

Source Review (NSR) Settlements (Appendix 3-3), and State Settlements (Appendix 3-4) in EPA Base 

Case v.4.10_FTransport ................................................................................................................. 67 
1

Introduction 

This documentation supplement describes the changes implemented for the Final Transport Rule 

analysis in EPA’s application of the Integrated Planning Model (IPM), the modeling platform used by 

EPA for U.S. electric power sector analysis. The changes described here resulted from comments 

received on the Proposed Transport Rule and on the Notice of Data Availability (NODA) for the 

Proposed Transport Rule, which were announced on September 1, 2010. The NODA included detailed 

documentation of the version of the model that EPA proposed using in the final rulemaking, a database 

of generating unit level input data used in the model, model run results, and user guides to input 

assumptions and model outputs. 

Comments received on the modeling platform fell into two basic categories: detailed comments on 

specific generating units and universal comments affecting broad categories of generating units. 

Changes resulting from detailed unit level comments (usually pertaining to distinct operating 

characteristics of specific generating units) are being documented separately as part of the "Transport Rule 

IPM Assumptions Response To Comments" document. EPA’s response to the universal modeling 

comments and the resulting updates to the modeling platform are presented here in the form of a 

documentation supplement for the Final Transport Rule. 

This documentation supplement is organized by comment topic. The presentation of each comment is 

divided into two sections. The first section summarizes the comment and EPA’s responses. The 

second section contains a mark-up of the relevant sections of the Documentation for EPA Base Case 

v.4.10 Using the Integrated Planning Model (www.epa.gov/airmarkets/progsregs/epaipm/BaseCasev410.html), indicating the exact modeling changes that resulted from the universal 

comments. To make it easier to recognize these mark-ups, they appear on a gray background, visually 

signaling that they are revisions of the previous documentation. 

 In the discussion below the following terminology is used: “EPA Base Case v.4.10_NODA version”1 

refers to base case released as part of the September 1, 201O NODA. Its assumptions and results 

were the subject of the public comments received by EPA. “EPA Base Case v.4.10_FTransport” 

incorporated the changes described below and was used in the modeling for the Final Transport Rule. 

It should also be noted that on March 16, 2011, EPA signed a Notice of Proposed Rulemaking for the 

Mercury and Air Toxics Standards (MATS). For that rulemaking EPA enhanced its power sector 

modeling platform with capabilities specifically needed for the Proposed MATS (for example the 

capability to model HCl emissions and controls, a coal-to-gas retrofit option, and updated assumptions 

for activated carbon injection for mercury control). These capabilities were also incorporated in the 

modeling for the Final Transport Rule. However, only those features relevant to the Final Transport 

Rule are documented here. These include provision of dry sorbent injection (DSI), accompanied by a 

fabric filter, as a retrofit option for SO2 (and HCl) emission control (documented in Addendum A at the 

end of this report) and updates of the State Power Sector Regulations and New Source Review (NSR) 

and State Settlements shown in Appendices 3-2 through 3-4 of the documentation supplement for the 

Proposed MATS (also found in Addendum B in this report). Appendices 3-2 through 3-4 reflect 

regulations and settlements that were in force through December 2010. Subsequent to freezing the 

assumptions for EPA Base Case v.4.10_FTransport, additional NSR settlements with Northern Indiana 

Public Service Company (www.epa.gov/compliance/resources/cases/civil/caa/nipsco.html, January 13, 

2011) and the Tennessee Valley Authority (www.epa.gov/compliance/resources/cases/civil/caa/tvacoalfired.html, April 14, 2011) were announced. For the TVA settlement EPA Base Case v.4.10_FTransport 

includes the provisions shown in the Appendix 3-3. Documentation of the full modeling capabilities for 

the Proposed MATS can be found in a separately issued report entitled Documentation Supplement for 

EPA Base Case v.4.10_Ptox – Updates for Proposed Toxics Rule, which is available for viewing and 

downloading at www.epa.gov/airmarkets/progsregs/epa-ipm/docs/suppdoc.pdf. 

 

1

In Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model the term “draft EPA 

Base Case v.4.10” was used when referring to what is now called “EPA Base Case v.4.10 NODA 

version”
2

1 Cogeneration Units 

1.1 Response to the Comments Received 

Comment Theme: Comments indicated that the extent of the operation and emissions from units that 

produce both steam and electricity (i.e., cogeneration units) in EPA Base Case v.4.10_NODA was 

considerably lower than actual operating experience. 

Discussion: In the draft base case which provoked these comments, cogeneration units were 

assigned the gross heat rates applicable to both the steam and electric portion of their operation. 

However, dispatch decisions in IPM are only based on the heat rate efficiency of the electric portion of a 

cogeneration unit. The lower a unit’s heat rate, the more efficient is its use of fuel for electricity 

generation, and the more likely it is to be dispatched. For electrical dispatch purposes, the net heat rate 

should have been used for cogeneration units. Since the net heat rate can be considerably lower than 

the gross heat rate, this revision should increase the extent that cogeneration units are operated. At the 

same time, since emissions from both the electric and steam portions of cogeneration units are covered 

by the Transport Rule, an emission multiplier should be used to ensure that total emissions are taken 

into account. The increased operation together with the emissions multiplier should correct the 

observation of low cogeneration operations and emissions and should address the points raised in the 

comments. 

Response: Based on these comments, a review was made of the representation of cogeneration units 

in draft EPA Base Case v.4.10. As a result this review, modifications were made so that the 

representation of cogeneration units would better reflect the extent of their operation and emissions. In 

particular, the following revisions were made. 

(1) In the draft base case, gross heat rates had been assigned to cogeneration units. That is, the heat 

rates (efficiency) of cogeneration units were calculated by summing the energy content of the fuel 

consumed for both steam and power generation and then dividing this sum by the electricity 

generated. Factoring in both the fuel consumed in producing steam and electricity when calculating 

the gross heat rate made the cogeneration units less efficient for electricity generation than their 

operating experience indicated. In the base case for the final Transport Rule net heat rates (heat 

content of fuel consumed for power generation divided by their generation) are assigned to 

cogeneration units. This will more accurately reflect their electric generation efficiency and make 

cogeneration units more economic to dispatch. 

(2) In conjunction with the use of net heat rates for cogeneration units in the base case for the final 

Transport Rule, cogeneration units are allowed to dispatch up to the availabilities assumed for the 

particular generation technology or up to their historic capacity factors (derived by taking the 

maximum historical capacity factor reported for the unit in EIA Form 860 for years 2006-2010). 

These limits are intended to prevent dispatch patterns that exceed the reported technical 

capabilities of these units. In cases where the maximum reported capacity factors is below 15%, a 

capacity factor of 15% is used as a limit, since historical capacity factor values below 15% are not 

considered to reflect the generation capability of the unit. 

(3) Even though the dispatch of cogeneration units in the Final Transport Rule will be based on their 

electric power (net) heat rate characteristics, the emissions from both power and steam production 

will be taken into account, since for cogeneration units the Transport Rule covers the emissions 

attributable to both electric and steam generation. To capture these total emissions a multiplier 

(derived by dividing the total fuel consumed for both steam and power by the fuel consumed for 

power) is applied to the power only emissions. 

1.2 Resulting Updates 

The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning 

Model show the updates that were implemented for the Final Transport Rule analysis in EPA Base 

Case v4.10_FTransport. 
3

Add the following appendix at the end of Chapter 3: 

3.5.2 Capacity Factor 

Add the following paragraph at the end of this section: 

To prevent dispatch patterns that exceed their reported technical capabilities, cogeneration units are 

allowed to dispatch up to the availabilities assumed for the particular generation technology or up to 

their historic capacity factors (derived by taking the maximum historical capacity factor reported for 

the unit in EIA Form 860 for years 2006-2010). In cases where the maximum reported capacity 

factors is below 15%, a capacity factor of 15% is used as a limit, since historical capacity factor 

values below 15% are not considered to reflect the generation capability of the unit. Appendix 3-10 

shows the capacity factor upper bounds for all the existing cogeneration units that are represented 

in EPA Base Case v.4.10. 

3.8 Heat Rate 

Add the following paragraph at the end of this section: 

For cogeneration units only, the heating value of the fuel combusted for electricity generation is 

used to derive the heat rate, since dispatch decisions in IPM are only based on the heat rate 

efficiency of the electric portion of a cogeneration unit. Known as a cogeneration unit’s net heat 

rate, it is calculated by dividing heat content of fuel consumed for power generation by electric 

generated from this fuel. To capture the total emissions from the cogeneration unit, a multiplier 

(derived by dividing the total fuel consumed for both steam and power by the fuel consumed for 

power) is applied to the power only emissions. Appendix 3-10 shows the heat rate and emission 

multipliers of all the existing cogeneration units that are represented in EPA Base Case v.4.10. For 

purposes of comparison Appendix 3-10 includes the net heat rate values currently used in modeling 

and the gross heat rate used prior to correcting the representation as a result of comments received 

in the September 2010 Notice of Data Availability (NODA). The net heat rates appear in the column 

labeled “'Post-NODA Heat Rate (Btu/kWh).” The gross heat rates appear in the column labeled 

“NODA Heat Rate (Btu/kWh).” Since the net heat rate cannot exceed the gross heat rate, instances 

where the value of the “'Post-NODA Heat Rate (Btu/kWh)” exceeds the value of the “NODA Heat 

Rate (Btu/kWh)” were caused by a change in the source of the data between the NODA and postNODA period. Such instances are highlighted and explained in Appendix 3-10. 
4 

Appendix 3‐10. Cogeneration Units ‐ Heat Rates (Before and After NODA Comments), Capacity Factor Upper Bounds, 

= Higher Post‐NODA Heat Rate Due to Higher Reported Value in AEO 2010 than i= Higher Post‐NODA Heat Rate Based on NODA Comment= Higher Post‐NODA Heat Rate Based on Net Heat Rate Reported in EIA Form 92

Plant Name UniqueID_Final PlantType

Region

Name

Capacity

(MW)

NODA

Heat Rate

(Btu/kWh)

Post‐NODA

Heat Rate

(Btu/kWh)

ACE Cogeneration Facility 10002_B_CFB Coal Steam CA‐S 101 10921 105Trigen Colorado Energy 10003_B_BLR1 O/G Steam RMPA 8.1 11972 83Trigen Colorado Energy 10003_B_BLR2 O/G Steam RMPA 8.1 11964 83Trigen Colorado Energy 10003_B_BLR3 Coal Steam RMPA 8.1 10331 83Trigen Colorado Energy 10003_B_BLR4 Coal Steam RMPA 8.1 10331 83Trigen Colorado Energy 10003_B_BLR5 Coal Steam RMPA 8.1 11768 83Baptist Medical Center 10008_G_CG‐3 IC Engine FRCC 0.50 13298 131Baptist Medical Center 10008_G_TG‐1 Combustion Turbine FRCC 2.3 15981 158Baptist Medical Center 10008_G_TG‐2 Combustion Turbine FRCC 2.2 15981 87Baptist Medical Center 10008_G_TG‐3 Combustion Turbine FRCC 2.7 15981 87Baptist Medical Center 10008_G_TG‐4 Combustion Turbine FRCC 3.2 12503 87NRG Energy Center Dover 10030_B_COGEN1 Coal Steam MACE 16.0 11782 117Greater Detroit Resource Recovery 10033_B_11 Municipal Solid Waste MECS 21.2 19338 83Greater Detroit Resource Recovery 10033_B_12 Municipal Solid Waste MECS 21.2 19338 83Greater Detroit Resource Recovery 10033_B_13 Municipal Solid Waste MECS 21.2 19338 83Gilroy Power Plant 10034_G_GEN1 Combined Cycle CA‐N 90.0 8330 83Gilroy Power Plant 10034_G_GEN2 Combined Cycle CA‐N 40.0 8330 83Logan Generating Plant 10043_B_B01 Coal Steam MACE 219 9890 98Central Utilities Plant LAX 10048_G_GEN1 Combustion Turbine CA‐S 4.0 15981 87Central Utilities Plant LAX 10048_G_GEN2 Combustion Turbine CA‐S 4.0 15981 87Cogentrix Virginia Leasing Corporation 10071_B_1A Coal Steam VAPW 19.2 11354 108Cogentrix Virginia Leasing Corporation 10071_B_1B Coal Steam VAPW 19.2 10331 103Cogentrix Virginia Leasing Corporation 10071_B_1C Coal Steam VAPW 19.2 10331 103
5 

Cogentrix Virginia Leasing Corporation 10071_B_2A Coal Steam VAPW 19.2 11353 108Cogentrix Virginia Leasing Corporation 10071_B_2B Coal Steam VAPW 19.2 10331 103Cogentrix Virginia Leasing Corporation 10071_B_2C Coal Steam VAPW 19.2 10331 103Pedricktown Cogen Plant 10099_G_GEN1 Combined Cycle MACE 79.2 8350 79Pedricktown Cogen Plant 10099_G_GEN2 Combined Cycle MACE 36.5 8350 79Frito‐Lay Cogen Plant 10110_G_GEN1 Combustion Turbine CA‐N 5.1 15981 158John B Rich Memorial Power Station 10113_B_CFB1 Coal Steam MACW 40.0 11190 83John B Rich Memorial Power Station 10113_B_CFB2 Coal Steam MACW 40.0 10331 83Harrisburg Facility 10118_B_1 Municipal Solid Waste MACW 6.9 19338 83Harrisburg Facility 10118_B_2 Municipal Solid Waste MACW 6.9 19338 83Harrisburg Facility 10118_B_3 Municipal Solid Waste MACW 6.9 19338 83Indiana University of Pennsylvania 10129_G_GEN1 IC Engine MACW 6.0 13298 94Indiana University of Pennsylvania 10129_G_GEN2 IC Engine MACW 6.0 13298 94Indiana University of Pennsylvania 10129_G_GEN3 IC Engine MACW 6.0 13298 94Indiana University of Pennsylvania 10129_G_GEN4 IC Engine MACW 6.0 13298 94Sierra Pacific Lincoln Facility 10144_G_GEN4 Biomass CA‐N 17.2 15517 83Fresno Cogen Partners 10156_G_GEN2 Combined Cycle CA‐N 6.0 7651 85Fresno Cogen Partners 10156_G_GEN3 Combined Cycle CA‐N 21.9 7651 85Fresno Cogen Partners 10156_G_GEN4 Combined Cycle CA‐N 45.0 7651 85Cardinal Cogen 10168_G_GTG1 Combined Cycle CA‐N 32.5 9939 97Cardinal Cogen 10168_G_STG1 Combined Cycle CA‐N 9.4 9939 97Carson Cogeneration 10169_G_GEN1 Combined Cycle CA‐S 41.3 8994 85Carson Cogeneration 10169_G_GEN2 Combined Cycle CA‐S 8.0 8994 85Metro Wastewater Reclamation District 10180_G_1 Non‐Fossil Waste RMPA 1.2 14283 87Metro Wastewater Reclamation District 10180_G_2 Non‐Fossil Waste RMPA 1.2 14283 87Metro Wastewater Reclamation District 10180_G_3 Non‐Fossil Waste RMPA 1.2 14283 87Metro Wastewater Reclamation District 10180_G_4 Non‐Fossil Waste RMPA 1.2 14283 87Metro Wastewater Reclamation District 10180_G_5 Non‐Fossil Waste RMPA 2.5 10000 87Metro Wastewater Reclamation District 10180_G_6 Non‐Fossil Waste RMPA 2.5 10000 87Central Utility Plant 10184_G_EG1 IC Engine ERCT 4.3 13298 131Central Utility Plant 10184_G_EG2 IC Engine ERCT 3.2 13298 131Central Utility Plant 10184_G_TG1 O/G Steam ERCT 0.23 11425 100IMC Phosphates Company Uncle Sam 10198_G_GEN1 Non‐Fossil Waste ENTG 10.2 13102 98IMC Phosphates Company Uncle Sam 10198_G_GEN2 Non‐Fossil Waste ENTG 10.2 13102 98Hercules Missouri Chemical Works 10207_B_1 Coal Steam GWAY 5.7 12508 83Hercules Missouri Chemical Works 10207_B_2 Coal Steam GWAY 5.7 12508 83Hercules Missouri Chemical Works 10207_B_3 Coal Steam GWAY 5.7 12508 83Snowbird Power Plant 10215_G_1367 IC Engine NWPE 0.59 13298 87Snowbird Power Plant 10215_G_1391 IC Engine NWPE 0.59 13298 87Snowbird Power Plant 10215_G_1392 IC Engine NWPE 0.59 13298 87Alabama River Pulp 10216_B_PB1 Biomass SOU 22.3 15517 83
6 

Alabama River Pulp 10216_B_RB1 Non‐Fossil Waste SOU 22.3 13102 83Leaf River Cellulose LLC 10233_B_PB Biomass SOU 37.5 15517 83Leaf River Cellulose LLC 10233_B_RB Non‐Fossil Waste SOU 12.5 13102 83King City Power Plant 10294_G_GTG Combined Cycle CA‐N 73.0 7990 79King City Power Plant 10294_G_STG Combined Cycle CA‐N 38.0 7990 79Bayou Cogen Plant 10298_G_GEN1 Combustion Turbine ERCT 65.0 15981 87Bayou Cogen Plant 10298_G_GEN2 Combustion Turbine ERCT 65.0 15981 87Bayou Cogen Plant 10298_G_GEN3 Combustion Turbine ERCT 65.0 15981 87Bayou Cogen Plant 10298_G_GEN4 Combustion Turbine ERCT 65.0 15981 87Bellingham Cogeneration Facility 10307_G_CT1 Combined Cycle NENG 102 8300 79Bellingham Cogeneration Facility 10307_G_CT2 Combined Cycle NENG 102 8300 79Bellingham Cogeneration Facility 10307_G_ST1 Combined Cycle NENG 60.0 8300 79Sayreville Cogeneration Facility 10308_G_CT1 Combined Cycle MACE 98.0 8650 82Sayreville Cogeneration Facility 10308_G_CT2 Combined Cycle MACE 98.0 8650 82Sayreville Cogeneration Facility 10308_G_ST1 Combined Cycle MACE 75.0 8650 82Central Power & Lime 10333_B_1 Coal Steam FRCC 139 10896 103Foster Wheeler Martinez 10342_G_TG1 Combined Cycle CA‐N 35.0 8600 82Foster Wheeler Martinez 10342_G_TG2 Combined Cycle CA‐N 35.0 8600 82Foster Wheeler Martinez 10342_G_TG3 Combined Cycle CA‐N 33.5 8600 82Foster Wheeler Mt Carmel Cogen 10343_B_SG‐101 Coal Steam MACW 43.0 12500 118Charleston Resource Recovery Facility 10344_B_B1 Municipal Solid Waste VACA 4.8 19338 95Charleston Resource Recovery Facility 10344_B_B2 Municipal Solid Waste VACA 4.8 19338 95Greenleaf 2 Power Plant 10349_G_GEN1 Combustion Turbine CA‐N 49.5 10578 87Greenleaf 1 Power Plant 10350_G_GEN1 Combined Cycle CA‐N 42.0 8290 61Greenleaf 1 Power Plant 10350_G_GEN2 Combined Cycle CA‐N 8.0 8290 61Cogentrix Hopewell 10377_B_1A Coal Steam VAPW 18.2 10331 91Cogentrix Hopewell 10377_B_1B Coal Steam VAPW 18.2 11360 91Cogentrix Hopewell 10377_B_1C Coal Steam VAPW 18.2 10331 91Cogentrix Hopewell 10377_B_2A Coal Steam VAPW 18.2 11359 91Cogentrix Hopewell 10377_B_2B Coal Steam VAPW 18.2 10331 91Cogentrix Hopewell 10377_B_2C Coal Steam VAPW 18.2 10331 91Primary Energy Southport 10378_B_1A Coal Steam VACA 17.8 11362 113Primary Energy Southport 10378_B_1B Coal Steam VACA 17.8 10331 103Primary Energy Southport 10378_B_1C Coal Steam VACA 17.8 10331 103Primary Energy Southport 10378_B_2A Coal Steam VACA 17.8 11361 113Primary Energy Southport 10378_B_2B Coal Steam VACA 17.8 10331 103Primary Energy Southport 10378_B_2C Coal Steam VACA 17.8 10331 103Primary Energy Roxboro 10379_B_1A Coal Steam VACA 18.7 11362 113Primary Energy Roxboro 10379_B_1B Coal Steam VACA 18.7 10331 103Primary Energy Roxboro 10379_B_1C Coal Steam VACA 18.7 10331 103Elizabethtown Power LLC 10380_B_A BLR Coal Steam 16.0 Not in dB 111
7 

Elizabethtown Power LLC 10380_B_B BLR Coal Steam 16.0 Not in dB 111Green Power Kenansville 10381_B_1A Biomass VACA 16.2 11564 114Green Power Kenansville 10381_B_1B Biomass VACA 16.2 15517 114Lumberton 10382_B_UNIT1 Coal Steam 16.0 Not in dB 112Lumberton 10382_B_UNIT2 Coal Steam 16.0 Not in dB 112Edgecombe GenCo 10384_B_1A Coal Steam VAPW 28.9 11325 110Edgecombe GenCo 10384_B_1B Coal Steam VAPW 28.9 10331 103Edgecombe GenCo 10384_B_2A Coal Steam VAPW 28.9 11325 110Edgecombe GenCo 10384_B_2B Coal Steam VAPW 28.9 10331 103Little Company of Mary Hospital 10400_G_GEN1 Combustion Turbine COMD 3.2 15981 87Laidlaw Energy

& Environmental 10403_G_ALLI Combined Cycle UPNY 2.6 11860 118

Laidlaw Energy

& Environmental 10403_G_CAT3 IC Engine UPNY 0.40 11100 111

Laidlaw Energy

& Environmental 10403_G_CAT4 IC Engine UPNY 0.40 11100 111

Laidlaw Energy

& Environmental 10403_G_WEST Combined Cycle UPNY 0.70 11860 118

Kingsburg Cogen 10405_G_GEN1 Combined Cycle CA‐N 22.0 9832 84Kingsburg Cogen 10405_G_GEN2 Combined Cycle CA‐N 11.8 9832 84Inland Ontario Mill 10427_G_GEN1 Combustion Turbine CA‐S 34.0 15981 158Wisconsin Rapids Pulp Mill 10477_B_P1 Coal Steam WUMS 11.2 10331 83Wisconsin Rapids Pulp Mill 10477_B_P2 Coal Steam WUMS 11.2 10331 83Wisconsin Rapids Pulp Mill 10477_B_P3 O/G Steam WUMS 11.2 11332 83Wisconsin Rapids Pulp Mill 10477_B_R1 Non‐Fossil Waste WUMS 11.2 13102 83Wisconsin Rapids Pulp Mill 10477_B_R2 Non‐Fossil Waste WUMS 11.2 13102 83Wisconsin Rapids Pulp Mill 10477_B_R3 Non‐Fossil Waste WUMS 11.2 13102 83Pitchess Cogen Station 10478_G_GEN1 Combined Cycle CA‐S 21.5 10211 67Pitchess Cogen Station 10478_G_GEN2 Combined Cycle CA‐S 5.7 10211 67Rumford Cogeneration 10495_B_6 Coal Steam NENG 42.5 11058 83Rumford Cogeneration 10495_B_7 Coal Steam NENG 42.5 10331 83Kern River Cogeneration 10496_G_GTAG Combustion Turbine CA‐N 72.0 16509 87Kern River Cogeneration 10496_G_GTBG Combustion Turbine CA‐N 72.0 16509 87Kern River Cogeneration 10496_G_GTCG Combustion Turbine CA‐N 72.0 16509 87Kern River Cogeneration 10496_G_GTDG Combustion Turbine CA‐N 72.0 16509 87Mid‐Set Cogeneration 10501_G_K100 Combustion Turbine CA‐N 36.0 15506 87San Jose Cogeneration 10548_G_GEN1 Combustion Turbine CA‐N 5.6 15981 116Chambers Cogeneration LP 10566_B_BOIL1 Coal Steam MACE 131 10000 100Chambers Cogeneration LP 10566_B_BOIL2 Coal Steam MACE 131 10331 100Algonquin Windsor Locks 10567_G_GTG Combined Cycle NENG 26.0 10186 71Algonquin Windsor Locks 10567_G_STG Combined Cycle NENG 12.0 10186 71Sixth Street 1058_B_2 Coal Steam 13.6 Not in dB 125Sixth Street 1058_B_3 Coal Steam 13.6 Not in dB 145Sixth Street 1058_B_4 Coal Steam 13.6 Not in dB 145Sixth Street 1058_B_5 Coal Steam 13.6 Not in dB 145
8 

BP Wilmington Calciner 10601_G_GEN1 Coal Steam CA‐S 29.0 10331 98Ebensburg Power 10603_B_031 Coal Steam MACW 49.5 12500 125Domtar ‐ Woodland Mill 10613_B_3RB O/G Steam NENG 23.0 11844 83Domtar ‐ Woodland Mill 10613_B_9PB Biomass NENG 23.0 15517 83CH Resources Beaver Falls 10617_G_GEN1 Combined Cycle UPNY 52.5 8700 87CH Resources Beaver Falls 10617_G_GEN2 Combined Cycle UPNY 34.0 8700 87Civic Center 10623_G_GEN1 Combined Cycle CA‐S 18.5 9939 85Civic Center 10623_G_GEN2 Combined Cycle CA‐S 1.2 9939 85Wheelabrator Baltimore Refuse 10629_B_BLR1 Municipal Solid Waste MACS 20.4 19338 162Wheelabrator Baltimore Refuse 10629_B_BLR2 Municipal Solid Waste MACS 20.4 19338 162Wheelabrator Baltimore Refuse 10629_B_BLR3 Municipal Solid Waste MACS 20.4 19338 162Hopewell Cogeneration 10633_G_GT1 Combined Cycle 84.1 Not in dB 82Hopewell Cogeneration 10633_G_GT2 Combined Cycle 84.1 Not in dB 82Hopewell Cogeneration 10633_G_GT3 Combined Cycle 84.1 Not in dB 82Hopewell Cogeneration 10633_G_ST1 Combined Cycle 96.0 Not in dB 82Corona Cogen 10635_G_GEN1 Combustion Turbine CA‐S 40.0 15727 87Cambria Cogen 10641_B_B1 Coal Steam MACW 44.0 11076 122Cambria Cogen 10641_B_B2 Coal Steam MACW 44.0 10331 122Bear Mountain Cogen 10649_G_GEN1 Combustion Turbine CA‐N 46.0 13225 87Badger Creek Cogen 10650_G_GEN1 Combustion Turbine CA‐N 46.0 13225 87Burney Forest Products 10652_B_BLR1 Biomass CA‐N 15.5 15517 157Burney Forest Products 10652_B_BLR2 Biomass CA‐N 15.5 15517 157Sierra Pacific Sonora 54517_G_GEN2 Biomass CA‐N 5.5 15517 83AES Deepwater 10670_B_AAB001 Coal Steam ERCT 140 14500 118AES Shady Point 10671_B_1A Coal Steam SPPS 80.0 10471 104AES Shady Point 10671_B_1B Coal Steam SPPS 80.0 10331 103AES Shady Point 10671_B_2A Coal Steam SPPS 80.0 10469 104AES Shady Point 10671_B_2B Coal Steam SPPS 80.0 10331 103Cedar Bay Generating LP 10672_B_CBA Coal Steam FRCC 83.3 9504 93Cedar Bay Generating LP 10672_B_CBB Coal Steam FRCC 83.3 10331 93Cedar Bay Generating LP 10672_B_CBC Coal Steam FRCC 83.3 10331 93AES Thames 10675_B_A Coal Steam NENG 90.5 10173 94AES Thames 10675_B_B Coal Steam NENG 90.5 10331 94AES Beaver Valley Partners Beaver Valley 10676_B_2 Coal Steam RFCP 43.0 11621 109AES Beaver Valley Partners Beaver Valley 10676_B_3 Coal Steam RFCP 43.0 12508 109AES Beaver Valley Partners Beaver Valley 10676_B_4 Coal Steam RFCP 43.0 12508 109AES Beaver Valley Partners Beaver Valley 10676_B_5 Coal Steam RFCP 17.0 12508 109AES Placerita 10677_G_UNT1 Combined Cycle CA‐S 46.0 9900 98AES Placerita 10677_G_UNT2 Combined Cycle CA‐S 46.0 9900 98AES Placerita 10677_G_UNT3 Combined Cycle CA‐S 23.0 9900 98AES Warrior Run Cogeneration Facility 10678_B_BLR1 Coal Steam RFCP 180 11177 105
9 

Colorado Power Partners 10682_G_GT1 Combined Cycle RMPA 25.0 11860 88Colorado Power Partners 10682_G_GT2 Combined Cycle RMPA 25.0 11860 88Colorado Power Partners 10682_G_ST1 Combined Cycle RMPA 30.0 11860 88BCP 10683_G_GT3 Combined Cycle RMPA 32.0 11860 98BCP 10683_G_ST2 Combined Cycle RMPA 40.0 11860 98Argus Cogen Plant 10684_B_BLR25 Coal Steam CA‐S 25.0 10331 83Argus Cogen Plant 10684_B_BLR26 Coal Steam CA‐S 25.0 10331 83Westend Facility 10685_G_PINA Combustion Turbine CA‐S 15.0 15981 87Rapids Energy Center 10686_B_5 Biomass MRO 11.2 15517 131Rapids Energy Center 10686_B_6 Biomass MRO 11.2 20328 131Rapids Energy Center 10686_B_7 O/G Steam MRO 3.5 14500 115Rapids Energy Center 10686_B_8 O/G Steam MRO 3.5 11332 115Jackson County Resource Recovery 10722_G_1 Municipal Solid Waste MECS 3.0 19338 83Selkirk Cogen 10725_G_GEN1 Combined Cycle DSNY 72.6 8861 81Selkirk Cogen 10725_G_GEN2 Combined Cycle DSNY 9.2 8861 81Selkirk Cogen 10725_G_GEN3 Combined Cycle DSNY 79.7 8861 81Selkirk Cogen 10725_G_GEN4 Combined Cycle DSNY 79.7 8861 81Selkirk Cogen 10725_G_GEN5 Combined Cycle DSNY 124 8861 81Masspower 10726_G_GEN1 Combined Cycle NENG 82.2 8224 85Masspower 10726_G_GEN2 Combined Cycle NENG 82.2 8224 85Prairie Creek 1073_B_1 Coal Steam MRO 9.1 11595 115Prairie Creek 1073_B_2 Coal Steam MRO 10.2 12230 122Prairie Creek 1073_B_3 Coal Steam MRO 41.6 11090 110Prairie Creek 1073_B_4 Coal Steam MRO 125 10198 101Clear Lake Cogeneration Ltd 10741_G_G102 Combined Cycle ERCT 100 10540 55Clear Lake Cogeneration Ltd 10741_G_G103 Combined Cycle ERCT 100 10540 55Clear Lake Cogeneration Ltd 10741_G_G104 Combined Cycle ERCT 100 10540 55Clear Lake Cogeneration Ltd 10741_G_S101 Combined Cycle ERCT 52.0 10540 55Clear Lake Cogeneration Ltd 10741_G_S102 Combined Cycle ERCT 14.0 10540 55Morgantown Energy Facility 10743_B_CFB1 Coal Steam RFCP 25.0 11298 86Morgantown Energy Facility 10743_B_CFB2 Coal Steam RFCP 25.0 10331 86Midland Cogeneration Venture 10745_G_1G12 IC Engine MECS 5.2 11585 115Midland Cogeneration Venture 10745_G_BP15 Combined Cycle MECS 13.4 8974 72Midland Cogeneration Venture 10745_G_GT10 Combined Cycle MECS 84.0 8974 72Midland Cogeneration Venture 10745_G_GT11 Combined Cycle MECS 84.0 8974 72Midland Cogeneration Venture 10745_G_GT12 Combined Cycle MECS 84.0 8974 72Midland Cogeneration Venture 10745_G_GT13 Combined Cycle MECS 84.0 8974 72Midland Cogeneration Venture 10745_G_GT14 Combined Cycle MECS 84.0 8974 72Midland Cogeneration Venture 10745_G_GT3 Combined Cycle MECS 84.0 8974 72Midland Cogeneration Venture 10745_G_GT4 Combined Cycle MECS 88.0 8974 72Midland Cogeneration Venture 10745_G_GT5 Combined Cycle MECS 88.0 8974 72
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Midland Cogeneration Venture 10745_G_GT6 Combined Cycle MECS 88.0 8974 72Midland Cogeneration Venture 10745_G_GT7 Combined Cycle MECS 88.0 8974 72Midland Cogeneration Venture 10745_G_GT8 Combined Cycle MECS 84.0 8974 72Midland Cogeneration Venture 10745_G_GT9 Combined Cycle MECS 84.0 8974 72Midland Cogeneration Venture 10745_G_ST1 Combined Cycle MECS 410 8974 72Midland Cogeneration Venture 10745_G_ST2 Combined Cycle MECS 380 8974 72Rifle Generating Station 10755_G_GT2 Combined Cycle RMPA 13.0 11860 104Rifle Generating Station 10755_G_GT3 Combined Cycle RMPA 13.0 11860 104Rifle Generating Station 10755_G_GT4 Combined Cycle RMPA 21.2 11860 104Rifle Generating Station 10755_G_ST1 Combined Cycle RMPA 21.2 11860 104Las Vegas Cogen LP 10761_G_GEN1 Combined Cycle SNV 41.0 8289 77Las Vegas Cogen LP 10761_G_GEN2 Combined Cycle SNV 9.0 8289 77Rio Bravo Jasmin 10768_B_CFB Coal Steam CA‐S 33.0 11568 114Rio Bravo Poso 10769_B_CFB Coal Steam CA‐N 33.0 11568 115Southampton Power Station 10774_B_1 Coal Steam 36.5 Not in dB 112Southampton Power Station 10774_B_2 Coal Steam 36.5 Not in dB 112E F Oxnard Energy Facility 10776_G_GTG Combustion Turbine CA‐S 48.5 15349 87Seaford Delaware Plant 10793_B_BLR1 O/G Steam MACE 9.0 14517 83Seaford Delaware Plant 10793_B_BLR3 O/G Steam MACE 9.0 14517 83Seaford Delaware Plant 10793_B_BLR5 O/G Steam MACE 9.0 12534 83Lowell Cogen Plant 10802_G_GEN1 Combined Cycle NENG 18.7 9800 98Lowell Cogen Plant 10802_G_GEN2 Combined Cycle NENG 6.3 9800 98Ogdensburg Power 10803_B_1 Biomass 26.0 Not in dB 85Ogdensburg Power 10803_G_GEN1 Biomass UPNY 8.3 8911 Retired Ogdensburg Power 10803_G_GEN2 Biomass UPNY 8.3 8911 Retired Ogdensburg Power 10803_G_GEN3 Biomass UPNY 8.3 8911 85Kenilworth Energy Facility 10805_G_GEN1 Combined Cycle MACE 22.5 10700 98Kenilworth Energy Facility 10805_G_GEN2 Combined Cycle MACE 4.5 10700 98Riverside 1081_B_7 Coal Steam MRO 2.5 12508 124Riverside 1081_B_8 Coal Steam MRO 2.5 12508 124Riverside 1081_B_9 Coal Steam MRO 130 10720 107NTC/MCRD Energy Facility 10810_G_GEN1 Combined Cycle CA‐S 21.6 10013 77NTC/MCRD Energy Facility 10810_G_GEN2 Combined Cycle CA‐S 2.2 10013 77Naval Station Energy Facility 10811_G_GEN1 Combined Cycle CA‐S 36.7 11520 81Naval Station Energy Facility 10811_G_GEN2 Combined Cycle CA‐S 9.8 11520 81Naval Station Energy Facility 10811_G_GEN3 Combined Cycle CA‐S 4.8 11520 81North Island Energy Facility 10812_G_GEN1 Combined Cycle CA‐S 33.5 9194 68North Island Energy Facility 10812_G_GEN2 Combined Cycle CA‐S 3.5 9194 68Ada Cogeneration LP 10819_G_GEN1 Combined Cycle MECS 23.0 8950 58Ada Cogeneration LP 10819_G_GEN2 Combined Cycle MECS 6.4 8950 58Walter Scott Jr. Energy Center 1082_B_3 Coal Steam MRO 690 10927 109
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Coca Cola Bottling of New York 10829_G_ENG1 IC Engine DSNY 0.60 12942 Retired Coca Cola Bottling of New York 10829_G_ENG2 IC Engine DSNY 0.60 12942 Retired Coca Cola Bottling of New York 10829_G_ENG3 IC Engine DSNY 0.60 13080 Retired Silver Bay Power 10849_B_BLR1 Coal Steam 36.0 Not in dB 96Silver Bay Power 10849_B_BLR2 Coal Steam 69.0 Not in dB 96Mojave Cogen 10850_G_GEN1 Combined Cycle CA‐S 40.0 11600 78Mojave Cogen 10850_G_GEN2 Combined Cycle CA‐S 15.3 11600 78Biomass One LP 10869_B_NORTH Biomass PNW 8.5 15517 120Biomass One LP 10869_B_SOUTH Biomass PNW 14.0 15517 120Medical Area Total Energy Plant 10883_B_GTHSG1 O/G Steam NENG 3.1 11332 83Medical Area Total Energy Plant 10883_B_GTHSG2 O/G Steam NENG 3.1 11332 83Medical Area Total Energy Plant 10883_B_HSG1 O/G Steam NENG 3.1 11332 83Medical Area Total Energy Plant 10883_B_HSG2 O/G Steam NENG 3.1 11332 83Medical Area Total Energy Plant 10883_B_PSG1 O/G Steam NENG 3.1 11332 83Medical Area Total Energy Plant 10883_B_PSG2 O/G Steam NENG 3.1 11332 83Medical Area Total Energy Plant 10883_B_PSG3 O/G Steam NENG 3.1 11332 83Medical Area Total Energy Plant 10883_G_CT1 Combustion Turbine NENG 12.5 12503 87Medical Area Total Energy Plant 10883_G_CT2 Combustion Turbine NENG 12.5 12503 87Medical Area Total Energy Plant 10883_G_DEG1 IC Engine NENG 6.0 13988 87Medical Area Total Energy Plant 10883_G_DEG2 IC Engine NENG 6.0 13988 87Medical Area Total Energy Plant 10883_G_DEG3 IC Engine NENG 6.0 13988 87Medical Area Total Energy Plant 10883_G_DEG4 IC Engine NENG 6.0 13988 87Medical Area Total Energy Plant 10883_G_DEG5 IC Engine NENG 6.0 13988 87Medical Area Total Energy Plant 10883_G_DEG6 IC Engine NENG 6.0 13988 87Ames Electric Services Power Plant 1122_B_7 Coal Steam MRO 33.0 12926 129Ames Electric Services Power Plant 1122_B_8 Coal Steam MRO 70.0 12926 129Muscatine Plant #1 1167_B_8 Coal Steam MRO 35.0 15279 152Louisiana 1 1391_G_1A Combined Cycle ENTG 18.0 10472 55Louisiana 1 1391_G_2A Combined Cycle ENTG 55.0 10472 55Louisiana 1 1391_G_3A Combined Cycle ENTG 55.0 10472 55Louisiana 1 1391_G_4A Combined Cycle ENTG 100 10472 55Louisiana 1 1391_G_5A Combined Cycle ENTG 154 10472 55R S Nelson 1393_B_1A Coal Steam ENTG 107 11041 110R S Nelson 1393_B_2A Coal Steam ENTG 106 11041 110R S Nelson 1393_B_3 O/G Steam ENTG 153 10476 104R S Nelson 1393_B_4 O/G Steam ENTG 500 10419 104Kendall Square Station 1595_G_1 Combined Cycle NENG 15.0 8658 89Kendall Square Station 1595_G_2 Combined Cycle NENG 20.0 8658 89Kendall Square Station 1595_G_3 Combined Cycle NENG 21.7 8658 89Kendall Square Station 1595_G_GEN4 Combined Cycle NENG 180 8658 89Apache Station 160_G_GT1 Combined Cycle AZNM 10.0 11855 110
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Apache Station 160_G_ST1 Combined Cycle AZNM 72.0 11855 110Mistersky 1822_B_5 O/G Steam 163 Not in dB 145Mistersky 1822_B_6 O/G Steam 163 Not in dB 145Mistersky 1822_B_7 O/G Steam 163 Not in dB 145M L Hibbard 1897_B_3 Biomass MRO 33.3 14500 145M L Hibbard 1897_B_4 Biomass MRO 15.3 14500 145Hibbing 1979_B_1 Coal Steam MRO 10.2 10331 103Hibbing 1979_B_2 Coal Steam MRO 10.2 10331 103Hibbing 1979_B_3 Coal Steam MRO 10.2 9906 99Hibbing 1979_B_wood Biomass MRO 20.0 14500 157New Ulm 2001_B_1 O/G Steam MRO 3.1 14500 145New Ulm 2001_B_2 O/G Steam MRO 3.1 14500 145New Ulm 2001_B_4 O/G Steam MRO 16.3 14500 145Virginia 2018_B_10 O/G Steam MRO 9.7 11804 118Virginia 2018_B_7 Coal Steam MRO 9.7 12245 122Virginia 2018_B_9 Coal Steam MRO 9.7 11947 119Virginia 2018_B_wood Biomass MRO 15.0 14500 157Willmar 2022_B_2 O/G Steam MRO 3.0 14500 145Willmar 2022_B_3 Coal Steam MRO 20.4 12260 122Chevron Oil 2047_G_1 Combustion Turbine SOU 15.0 15154 151Chevron Oil 2047_G_2 Combustion Turbine SOU 15.0 15154 151Chevron Oil 2047_G_3 Combustion Turbine SOU 16.0 15188 151Chevron Oil 2047_G_4 Combustion Turbine SOU 16.0 15188 151Chevron Oil 2047_G_5 Combustion Turbine SOU 65.0 13160 131Raton 2468_G_5 Coal Steam AZNM 6.9 14200 142East River 2493_B_60 O/G Steam NYC 134 12215 128East River 2493_B_70 O/G Steam NYC 182 12215 119Ravenswood 2500_G_4 Combined Cycle NYC 231 7933 150AES Westover 2526_B_11 Coal Steam UPNY 21.9 12184 110AES Westover 2526_B_12 Coal Steam UPNY 21.9 12508 110AES Westover 2526_B_13 Coal Steam UPNY 84.0 11000 110Hamilton 2917_G_GT2 Combined Cycle RFCO 12.0 36790 150Johnsonville 3406_B_1 Coal Steam TVA 106 11957 119Johnsonville 3406_B_10 Coal Steam TVA 141 10649 106Johnsonville 3406_B_2 Coal Steam TVA 106 11957 119Johnsonville 3406_B_3 Coal Steam TVA 106 11957 119Johnsonville 3406_B_4 Coal Steam TVA 106 11957 119Johnsonville 3406_B_5 Coal Steam TVA 106 11031 110Johnsonville 3406_B_6 Coal Steam TVA 106 11031 110Johnsonville 3406_B_7 Coal Steam TVA 141 10649 106Johnsonville 3406_B_8 Coal Steam TVA 141 10649 106
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Johnsonville 3406_B_9 Coal Steam TVA 141 10649 106Valley 4042_B_1 Coal Steam WUMS 70.0 13428 134Valley 4042_B_2 Coal Steam WUMS 70.0 13428 134Valley 4042_B_3 Coal Steam WUMS 70.0 13199 131Valley 4042_B_4 Coal Steam WUMS 70.0 13199 131Manitowoc 4125_B_5 Coal Steam WUMS 1.5 11365 113Manitowoc 4125_B_6 Coal Steam WUMS 18.0 11470 114Manitowoc 4125_B_7 Coal Steam WUMS 18.0 10331 103Manitowoc 4125_B_8 Coal Steam WUMS 20.6 10331 103Manitowoc 4125_B_9 Coal Steam WUMS 30.0 10331 103Menasha 4127_B_5 Coal Steam WUMS 6.9 10331 88Menasha 4127_B_B23 Coal Steam 8.50 Not in dB 118Menasha 4127_B_B24 Coal Steam 14.5 Not in dB 118Pittsfield Generating LP 50002_G_GEN1 Combined Cycle NENG 33.8 10808 90Pittsfield Generating LP 50002_G_GEN2 Combined Cycle NENG 33.8 10808 90Pittsfield Generating LP 50002_G_GEN3 Combined Cycle NENG 33.8 10808 90Pittsfield Generating LP 50002_G_GEN4 Combined Cycle NENG 39.6 10808 90Chalk Cliff Cogen 50003_G_GEN1 Combustion Turbine CA‐N 46.0 13225 87Linden Cogen Plant 50006_G_GTG1 Combined Cycle MACE 90.0 9174 67Linden Cogen Plant 50006_G_GTG2 Combined Cycle MACE 90.0 9174 67Linden Cogen Plant 50006_G_GTG3 Combined Cycle MACE 90.0 9174 67Linden Cogen Plant 50006_G_GTG4 Combined Cycle MACE 90.0 9174 67Linden Cogen Plant 50006_G_GTG5 Combined Cycle MACE 90.0 9174 67Linden Cogen Plant 50006_G_GTG6 Combined Cycle MACE 182 9174 67Linden Cogen Plant 50006_G_STG1 Combined Cycle MACE 89.0 9174 67Linden Cogen Plant 50006_G_STG2 Combined Cycle MACE 89.0 9174 67Linden Cogen Plant 50006_G_STG3 Combined Cycle MACE 89.0 9174 67Nelson Industrial Steam and Operating Company 50030_B_1A Coal Steam 107 Not in dB 110Nelson Industrial Steam and Operating Company 50030_B_2A Coal Steam 106 Not in dB 110Kline Township Cogen Facility 50039_B_1 Coal Steam MACW 50.0 12138 121Pacific Lumber 50049_B_BLRA Biomass CA‐N 16.2 15517 157Pacific Lumber 50049_B_BLRB Biomass CA‐N 8.7 15517 157Pacific Lumber 50049_B_BLRC Biomass CA‐N 8.7 15517 157Borger Plant 50067_B_1 Fossil Waste SPPS 16.0 9107 83Borger Plant 50067_B_2 Fossil Waste SPPS 16.0 9107 83Sierra Power 50068_G_WEST Biomass CA‐S 7.0 15517 145Marcus Hook Refinery Cogen 50074_G_GEN1 Combustion Turbine MACE 50.0 10973 87EQ Waste Energy Services 50077_G_CAT1 Landfill Gas MECS 0.50 13388 136EQ Waste Energy Services 50077_G_CAT2 Landfill Gas MECS 0.30 13388 136EQ Waste Energy Services 50077_G_CAT3 Landfill Gas MECS 0.30 13388 136EQ Waste Energy Services 50077_G_CAT4 Landfill Gas MECS 0.30 13388 136
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Trigen Trenton Energy 50094_G_7213 IC Engine MACE 3.0 11625 87Trigen Trenton Energy 50094_G_7214 IC Engine MACE 3.0 11625 87Tillotson Rubber 50095_B_EU1 Biomass NENG 0.70 14594 83Tillotson Rubber 50095_B_EU2 O/G Steam NENG 0.60 12364 92Sierra Pacific Anderson Facility 55049_G_GEN1 Biomass CA‐N 5.0 15517 83United Cogen 50104_G_G‐1 Combined Cycle CA‐N 22.0 9939 97United Cogen 50104_G_G‐2 Combined Cycle CA‐N 7.0 9939 97Collins Pine Project 10661_B_4 Biomass CA‐N 12.0 15517 83Sierra Pacific Burney Facility 50110_B_BLR1 Biomass CA‐N 16.3 15517 83Sierra Pacific Quincy Facility 50112_B_BLR1 Biomass CA‐N 14.4 15517 83Susanville 50113_G_GEN1 Biomass 11.0 Not in dB 157Susanville 50113_G_GEN2 Biomass 2.00 Not in dB 157US Borax 50115_G_GEN1 Combustion Turbine CA‐N 39.0 15981 87ConocoPhillips Rodeo Refinery 50119_G_GENA Non‐Fossil Waste CA‐N 13.5 13102 87ConocoPhillips Rodeo Refinery 50119_G_GENB Non‐Fossil Waste CA‐N 13.5 13102 87ConocoPhillips Rodeo Refinery 50119_G_GENC Non‐Fossil Waste CA‐N 13.5 13102 87Coalinga Cogeneration 50131_G_K100 Combustion Turbine CA‐N 36.0 15015 87Sycamore Cogeneration 50134_G_GTAG Combustion Turbine CA‐S 76.0 16038 87Sycamore Cogeneration 50134_G_GTBG Combustion Turbine CA‐S 76.0 16038 87Sycamore Cogeneration 50134_G_GTCG Combustion Turbine CA‐S 76.0 16038 87Sycamore Cogeneration 50134_G_GTDG Combustion Turbine CA‐S 76.0 16038 87Snider Industries 50141_G_WGN1 Biomass SPPS 5.0 15517 83Union Carbide Seadrift Cogen 50150_G_GE10 Combined Cycle ERCT 15.0 9489 93Union Carbide Seadrift Cogen 50150_G_GE11 Combined Cycle ERCT 35.0 9489 93Union Carbide Seadrift Cogen 50150_G_GEN5 Combined Cycle ERCT 15.0 9489 93Union Carbide Seadrift Cogen 50150_G_GEN6 Combined Cycle ERCT 35.0 9489 93Union Carbide Seadrift Cogen 50150_G_GEN7 Combined Cycle ERCT 6.0 9489 93Union Carbide Seadrift Cogen 50150_G_GEN8 Combined Cycle ERCT 35.0 9489 93Union Carbide Seadrift Cogen 50150_G_GEN9 Combined Cycle ERCT 15.0 9489 93Dow St Charles Operations 50152_G_CGN1 Combined Cycle ENTG 100 8004 80Dow St Charles Operations 50152_G_CGN2 Combined Cycle ENTG 100 8004 80Dow St Charles Operations 50152_G_CSTG Combined Cycle ENTG 50.0 8004 80Dow St Charles Operations 50152_G_CTG Combined Cycle ENTG 10.0 8004 80Dow St Charles Operations 50152_G_STG Combined Cycle ENTG 22.0 8004 80Berry Cogen 50170_G_GEN1 Combustion Turbine CA‐N 35.0 15981 87Rowan University 50173_G_GEN1 Combustion Turbine MACE 1.2 12503 124Watson Cogeneration 50216_G_GN91 Combined Cycle CA‐S 82.0 9939 55Watson Cogeneration 50216_G_GN92 Combined Cycle CA‐S 82.0 9939 55Watson Cogeneration 50216_G_GN93 Combined Cycle CA‐S 82.0 9939 55Watson Cogeneration 50216_G_GN94 Combined Cycle CA‐S 82.0 9939 55Watson Cogeneration 50216_G_GN95 Combined Cycle CA‐S 35.0 9939 55
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Watson Cogeneration 50216_G_GN96 Combined Cycle CA‐S 35.0 9939 55Texas Petrochemicals 50229_B_TPCBLR O/G Steam ERCT 35.0 11332 83Bucksport Mill 50243_B_5 O/G Steam NENG 23.3 11844 83Bucksport Mill 50243_B_6 O/G Steam NENG 23.3 11332 83Bucksport Mill 50243_B_7 O/G Steam NENG 23.3 11332 83Bucksport Mill 50243_B_8 Biomass NENG 23.3 15517 83Bucksport Mill 50243_G_GEN4 Combustion Turbine NENG 176 12435 99Archbald Power Station 50279_B_MAIN Landfill Gas MACW 20.0 13682 136Ripon Mill 50299_G_GEN1 Combustion Turbine CA‐N 46.5 15778 87San Gabriel Facility 50300_G_GEN1 Combustion Turbine CA‐S 39.0 16200 87Cornell University Central Heat 50368_G_TG1 Coal Steam UPNY 1 10331 96Cornell University Central Heat 50368_G_TG2 Coal Steam UPNY 5.3 10331 96Paxton Creek Cogeneration 50373_G_GEN1 IC Engine MACW 6.0 14993 88Paxton Creek Cogeneration 50373_G_GEN2 IC Engine MACW 6.0 14993 88Newark Bay Cogeneration Project 50385_G_GEN1 Combined Cycle MACE 42.0 8700 81Newark Bay Cogeneration Project 50385_G_GEN2 Combined Cycle MACE 42.0 8700 81Newark Bay Cogeneration Project 50385_G_GEN3 Combined Cycle MACE 34.0 8700 81Phillips 66 Carbon Plant 50388_B_K1 Coal Steam CA‐N 10.0 10331 103Phillips 66 Carbon Plant 50388_B_K2 Coal Steam CA‐N 10.0 10331 103P H Glatfelter 50397_B_1PB035 Coal Steam MACW 8.7 10331 83P H Glatfelter 50397_B_3PB033 Coal Steam MACW 4.0 12508 83P H Glatfelter 50397_B_4PB034 Coal Steam MACW 9.0 10331 83P H Glatfelter 50397_B_5PB036 Coal Steam MACW 36.1 10331 83P H Glatfelter 50397_B_REC037 Non‐Fossil Waste MACW 31.2 13102 83BP Chemicals Green Lake Plant 50404_G_TG2 Non‐Fossil Waste ERCT 15.0 13102 98BP Chemicals Green Lake Plant 50404_G_TG3 Non‐Fossil Waste ERCT 23.8 13102 98Mobile Energy Services LLC 50407_B_7PB Biomass SOU 14.4 15517 105Mobile Energy Services LLC 50407_B_8PB O/G Steam SOU 12.5 11425 105Mobile Energy Services LLC 50407_B_8RB O/G Steam SOU 13.2 11425 105Chester Operations 50410_B_10 Coal Steam MACE 36.0 10331 83Olmsted Waste Energy 50413_G_TG2 Municipal Solid Waste MRO 1.3 19338 117Olmsted Waste Energy 50413_G_TGI Municipal Solid Waste MRO 1.4 19338 117Bronx Zoo 50427_G_GEN1 IC Engine NYC 0.50 11600 87Bronx Zoo 50427_G_GEN2 IC Engine NYC 0.50 11600 87Bronx Zoo 50427_G_GEN3 IC Engine NYC 1.1 11600 87Bronx Zoo 50427_G_GEN4 IC Engine NYC 1.5 11600 87University of Michigan 50431_G_TG1 Combined Cycle MECS 11.5 6920 55University of Michigan 50431_G_TG10 Combined Cycle MECS 3.0 6920 55University of Michigan 50431_G_TG7 Combined Cycle MECS 11.5 6920 55University of Michigan 50431_G_TG8 Combined Cycle MECS 11.5 6920 55University of Michigan 50431_G_TG9 Combined Cycle MECS 3.0 6920 55
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S D Warren Westbrook 50447_B_17 O/G Steam NENG 11.9 11844 90S D Warren Westbrook 50447_B_18 O/G Steam NENG 11.9 11844 90S D Warren Westbrook 50447_B_20 Biomass NENG 11.9 15517 83S D Warren Westbrook 50447_B_21 Biomass NENG 26.9 15517 83Indeck Silver Springs Energy Center 50449_G_GEN1 Combined Cycle UPNY 33.7 8890 82Indeck Silver Springs Energy Center 50449_G_GEN2 Combined Cycle UPNY 17.2 8890 82Indeck Oswego Energy Center 50450_G_GEN1 Combined Cycle UPNY 30.1 9250 83Indeck Oswego Energy Center 50450_G_GEN2 Combined Cycle UPNY 16.2 9250 83Indeck Yerkes Energy Center 50451_G_GEN1 Combined Cycle UPNY 29.0 9870 93Indeck Yerkes Energy Center 50451_G_GEN2 Combined Cycle UPNY 19.4 9870 93Indeck Corinth Energy Center 50458_G_GEN1 Combined Cycle DSNY 76.5 8030 79Indeck Corinth Energy Center 50458_G_GEN2 Combined Cycle DSNY 55.0 8030 79Oxnard 50464_G_GEN1 Combustion Turbine CA‐S 21.5 15981 87Oxnard 50464_G_GEN2 Combustion Turbine CA‐S 45.0 15981 87American Ref‐Fuel of Niagara 50472_B_BLR1 O/G Steam UPNY 9.0 11332 83American Ref‐Fuel of Niagara 50472_B_BLR2 Biomass UPNY 9.0 15517 84American Ref‐Fuel of Niagara 50472_B_BLR3 Municipal Solid Waste UPNY 9.0 19338 83American Ref‐Fuel of Niagara 50472_B_BLR4 Municipal Solid Waste UPNY 9.0 19338 83Corpus Christi 50475_G_GEN1 Combustion Turbine ERCT 33.0 15981 87Bryant Sugar House 50483_B_B1 Biomass FRCC 4.4 15517 83Bryant Sugar House 50483_B_B2 Biomass FRCC 4.4 15517 83Bryant Sugar House 50483_B_B3 Biomass FRCC 4.4 15517 83Bryant Sugar House 50483_B_B4 Biomass FRCC 4.4 15517 83Bryant Sugar House 50483_B_B7 Biomass FRCC 4.4 15517 83Bryant Sugar House 50483_B_B8 Biomass FRCC 4.4 15517 83PPG Powerhouse C 50489_G_C1 Combined Cycle ENTG 55.0 9939 97PPG Powerhouse C 50489_G_C2 Combined Cycle ENTG 55.0 9939 97PPG Powerhouse C 50489_G_C3 Combined Cycle ENTG 52.0 9939 97PPG Powerhouse C 50489_G_C4 Combined Cycle ENTG 70.6 9939 97PPG Powerhouse C 50489_G_C5 Combined Cycle ENTG 70.6 9939 97Gas Utilization Facility 50492_G_1 Non‐Fossil Waste CA‐S 2.3 13102 87Gas Utilization Facility 50492_G_2 Non‐Fossil Waste CA‐S 2.3 13102 87Double C 50493_G_DC1 Combustion Turbine CA‐N 23.0 14379 87Double C 50493_G_DC2 Combustion Turbine CA‐N 23.0 14379 87Kern Front 50494_G_KF1 Combustion Turbine CA‐N 23.0 15423 87Kern Front 50494_G_KF2 Combustion Turbine CA‐N 23.0 15423 87High Sierra 50495_G_HS1 Combustion Turbine CA‐N 23.0 15410 87High Sierra 50495_G_HS2 Combustion Turbine CA‐N 23.0 15410 87Bayonne Cogen Plant 50497_G_GTG1 Combined Cycle MACE 36.0 9300 56Bayonne Cogen Plant 50497_G_GTG2 Combined Cycle MACE 36.0 9300 56Bayonne Cogen Plant 50497_G_GTG3 Combined Cycle MACE 36.0 9300 56
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Bayonne Cogen Plant 50497_G_STG1 Combined Cycle MACE 62.0 9300 56Capital District Energy Center 50498_G_GTG Combined Cycle NENG 34.3 9200 95Capital District Energy Center 50498_G_STG Combined Cycle NENG 21.0 9200 95Mosaic Co Mulberry Facility 50510_G_CGN1 Non‐Fossil Waste FRCC 19.5 13102 Retired SRI International Cogen Project 50537_G_GEN1 Combustion Turbine CA‐N 5.6 15981 87Black Hills Ontario Facility 50538_G_GEN1 Combustion Turbine CA‐S 4.5 15981 Retired Black Hills Ontario Facility 50538_G_GEN2 Combustion Turbine CA‐S 4.5 15981 Retired Rosemary Power Station 50555_G_GEN1 Combined Cycle VAPW 75.0 8900 99Rosemary Power Station 50555_G_GEN2 Combined Cycle VAPW 36.0 8900 99Rosemary Power Station 50555_G_GEN3 Combined Cycle VAPW 54.0 8900 99PowerSmith Cogeneration Project 50558_G_GT01 Combined Cycle SPPS 67.3 7272 80PowerSmith Cogeneration Project 50558_G_ST01 Combined Cycle SPPS 44.1 7272 80Eagle Point Cogeneration 50561_G_GTG1 Combined Cycle MACE 75.0 7933 79Eagle Point Cogeneration 50561_G_GTG2 Combined Cycle MACE 75.0 7933 79Eagle Point Cogeneration 50561_G_STG1 Combined Cycle MACE 45.0 7933 79McKittrick Cogen 50612_G_GEN1 Combustion Turbine CA‐N 46.0 15073 87TXU Sweetwater Generating Plant 50615_G_GT01 Combined Cycle ERCT 32.0 13157 131TXU Sweetwater Generating Plant 50615_G_GT02 Combined Cycle ERCT 72.0 13157 131TXU Sweetwater Generating Plant 50615_G_GT03 Combined Cycle ERCT 72.0 13157 131TXU Sweetwater Generating Plant 50615_G_STG1 Combined Cycle ERCT 64.0 13157 131Berry Cogen Tanne Hills 18 50622_G_GEN1 Combustion Turbine CA‐N 7.0 15899 87Berry Cogen Tanne Hills 18 50622_G_GEN2 Combustion Turbine CA‐N 7.0 15899 87Gaviota Oil Plant 50623_G_GENA Combustion Turbine CA‐S 3.0 15981 87Gaviota Oil Plant 50623_G_GENB Combustion Turbine CA‐S 3.0 15981 87Gaviota Oil Plant 50623_G_GENC Combustion Turbine CA‐S 3.0 15981 87Gaviota Oil Plant 50623_G_GEND Combustion Turbine CA‐S 3.0 15981 87ExxonMobil Beaumont Refinery 50625_B_22 Fossil Waste ENTG 16.7 9107 83ExxonMobil Beaumont Refinery 50625_B_24 O/G Steam ENTG 8.3 11425 111ExxonMobil Beaumont Refinery 50625_B_33 Fossil Waste ENTG 37.5 9107 83ExxonMobil Beaumont Refinery 50625_B_34 Fossil Waste ENTG 37.5 9107 83ExxonMobil Beaumont Refinery 50625_G_TG23 Combined Cycle ENTG 38.6 7933 63ExxonMobil Beaumont Refinery 50625_G_TG24 Combined Cycle ENTG 32.0 7933 63ExxonMobil Beaumont Refinery 50625_G_TG41 Combustion Turbine ENTG 152 12435 87ExxonMobil Beaumont Refinery 50625_G_TG42 Combustion Turbine ENTG 152 12435 87ExxonMobil Beaumont Refinery 50625_G_TG43 Combustion Turbine ENTG 152 12435 87Covanta Marion Inc 50630_B_BLR1 Municipal Solid Waste PNW 5.8 19338 162Covanta Marion Inc 50630_B_BLR2 Municipal Solid Waste PNW 5.8 19338 162Mosaic Co Martlow Facility 50633_G_GEN1 Non‐Fossil Waste FRCC 36.0 13102 98Mosaic Co Martlow Facility 50633_G_GEN2 Non‐Fossil Waste FRCC 44.0 13102 98Potlatch Idaho Pulp Paper 50637_B_1PWR O/G Steam PNW 1.4 14789 121Potlatch Idaho Pulp Paper 50637_B_2PWR O/G Steam PNW 1.4 14789 121
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Potlatch Idaho Pulp Paper 50637_B_4PWR Biomass PNW 27.2 15517 121Potlatch Idaho Pulp Paper 50637_B_4REC O/G Steam PNW 1.6 11332 115Potlatch Idaho Pulp Paper 50637_B_5REC Non‐Fossil Waste PNW 32.2 13102 121Sierra Pacific Quincy Facility 50112_B_BLR2 Biomass CA‐N 14.4 15517 83Covanta Indianapolis Energy 50647_G_GEN1 Municipal Solid Waste RFCO 5.0 19338 83Trigen Syracuse Energy 50651_B_1 Coal Steam UPNY 11.1 10000 83Trigen Syracuse Energy 50651_B_2 Coal Steam UPNY 11.1 10331 83Trigen Syracuse Energy 50651_B_3 Coal Steam UPNY 11.1 10331 83Trigen Syracuse Energy 50651_B_4 Coal Steam UPNY 11.1 10331 83Trigen Syracuse Energy 50651_B_5 Coal Steam UPNY 11.1 10331 83Trigen Syracuse Energy 50651_G_GEN2 Coal Steam UPNY 11.0 10000 83Thermo Power & Electric 50676_G_GEN1 Combined Cycle RMPA 30.0 8650 62Thermo Power & Electric 50676_G_GEN2 Combined Cycle RMPA 30.0 8650 62Thermo Power & Electric 50676_G_GEN3 Combined Cycle RMPA 8.0 8650 62KMS Crossroads 50693_G_DG‐1 IC Engine MACE 7.0 10100 101TCP 272 50707_G_LMA Combined Cycle RMPA 31.8 9400 95TCP 272 50707_G_LMB Combined Cycle RMPA 31.8 9400 95TCP 272 50707_G_LMC Combined Cycle RMPA 31.8 9400 95TCP 272 50707_G_LMD Combined Cycle RMPA 31.8 9400 95TCP 272 50707_G_LME Combined Cycle RMPA 31.8 9400 95TCP 272 50707_G_STA Combined Cycle RMPA 52.0 9400 95TCP 272 50707_G_STB Combined Cycle RMPA 52.0 9400 95Thermo Greeley 50709_G_GEN1 Combustion Turbine RMPA 37.0 14104 87BP Naperville Cogeneration Facility 50722_G_GEN1 Combustion Turbine COMD 7.0 12503 124Sterling Power Plant 50744_G_GEN1 Combined Cycle UPNY 38.8 8968 82Sterling Power Plant 50744_G_GEN2 Combined Cycle UPNY 16.0 8968 82Agnews Power Plant 50748_G_GEN1 Combined Cycle CA‐N 23.0 8944 78Agnews Power Plant 50748_G_GEN2 Combined Cycle CA‐N 7.3 8944 78Coalinga Cogeneration Facility 50750_G_GEN1 Combustion Turbine CA‐N 3.2 15981 87Coalinga Cogeneration Facility 50750_G_GEN2 Combustion Turbine CA‐N 3.2 15981 87Southeast Kern River Cogen 50751_G_GTG1 Combustion Turbine CA‐N 20.5 15981 87Southeast Kern River Cogen 50751_G_GTG2 Combustion Turbine CA‐N 3.0 15981 87Southeast Kern River Cogen 50751_G_GTG3 Combustion Turbine CA‐N 3.0 15981 87Viking Energy of Northumberland 50771_B_B1 Biomass MACW 16.0 15517 145EFS Parlin 50799_G_GT1 Combined Cycle MACE 38.0 10500 79EFS Parlin 50799_G_GT2 Combined Cycle MACE 38.0 10500 79EFS Parlin 50799_G_STG1 Combined Cycle MACE 25.0 10500 79EFS Parlin 50799_G_STG2 Combined Cycle MACE 25.0 10500 79Stone Container Florence Mill 50806_B_PB1 O/G Steam VACA 5.6 11844 83Stone Container Florence Mill 50806_B_PB3 Biomass VACA 7.6 15517 83Stone Container Florence Mill 50806_B_PB4 Coal Steam VACA 74.8 10331 83
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Stone Container Florence Mill 50806_B_RBF O/G Steam VACA 15.3 11844 83Stone Container Hopewell Mill 50813_B_CB1 Biomass VAPW 20.4 15517 83Stone Container Hopewell Mill 50813_B_RB1 Non‐Fossil Waste VAPW 20.4 13102 83CoGen Lyondell 50815_G_GEN1 Combined Cycle ERCT 64.0 9500 94CoGen Lyondell 50815_G_GEN2 Combined Cycle ERCT 64.0 9500 94CoGen Lyondell 50815_G_GEN3 Combined Cycle ERCT 64.0 9500 94CoGen Lyondell 50815_G_GEN4 Combined Cycle ERCT 64.0 9500 94CoGen Lyondell 50815_G_GEN5 Combined Cycle ERCT 64.0 9500 94CoGen Lyondell 50815_G_GEN6 Combined Cycle ERCT 64.0 9500 94CoGen Lyondell 50815_G_GEN7 Combined Cycle ERCT 64.0 9500 94TES Filer City Station 50835_B_1 Coal Steam MECS 30.0 11308 113TES Filer City Station 50835_B_2 Coal Steam MECS 30.0 10331 103Southeast Resource Recovery 50837_B_UNIT1 Municipal Solid Waste CA‐S 9.3 19338 162Southeast Resource Recovery 50837_B_UNIT2 Municipal Solid Waste CA‐S 9.3 19338 162Southeast Resource Recovery 50837_B_UNIT3 Municipal Solid Waste CA‐S 9.3 19338 162Weir Cogen Plant 50848_G_GT1 Combustion Turbine CA‐N 3.2 15981 158PE Berkeley 50849_G_GEN1 Combined Cycle CA‐N 21.0 9939 55PE Berkeley 50849_G_GEN2 Combined Cycle CA‐N 2.0 9939 55OLS Energy Chino 50850_G_GEN1 Combined Cycle CA‐S 22.5 8650 71OLS Energy Chino 50850_G_GEN2 Combined Cycle CA‐S 6.5 8650 71OLS Energy Camarillo 50851_G_GEN1 Combined Cycle CA‐S 21.5 8580 78OLS Energy Camarillo 50851_G_GEN2 Combined Cycle CA‐S 6.8 8580 78RPL Holdings 50852_G_GEN1 Combined Cycle MACE 51.0 10000 116RPL Holdings 50852_G_GEN2 Combined Cycle MACE 13.9 10000 116Onondaga Cogeneration 50855_G_GEN1 Combined Cycle UPNY 45.0 9188 Retired Onondaga Cogeneration 50855_G_GEN2 Combined Cycle UPNY 25.0 9188 Retired Onondaga Cogeneration 50855_G_GEN3 Combined Cycle UPNY 23.0 9188 Retired Kent County Waste to Energy Facility 50860_B_BLR1 Municipal Solid Waste MECS 7.9 19338 162Kent County Waste to Energy Facility 50860_B_BLR2 Municipal Solid Waste MECS 7.9 19338 162Sargent Canyon Cogeneration 50864_G_K100 Combustion Turbine CA‐N 30.0 14996 87Salinas River Cogeneration 50865_G_K100 Combustion Turbine CA‐N 33.0 15001 87Wheelabrator Sherman Energy Facility 50874_B_19425 Biomass 21.0 Not in dB 157Wheelabrator Norwalk Energy 50876_G_GEN1 Combined Cycle CA‐S 19.8 9280 78Wheelabrator Norwalk Energy 50876_G_GEN2 Combined Cycle CA‐S 6.6 9280 78Wheelabrator Frackville Energy 50879_B_BLR1 Coal Steam MACW 44.5 11503 92Wheelabrator Gloucester LP 50885_B_BLR1 Municipal Solid Waste 6.00 Not in dB 162Wheelabrator Gloucester LP 50885_B_BLR2 Municipal Solid Waste 6.00 Not in dB 162Northampton Generating Company 50888_B_BLR1 Coal Steam MACW 112 12174 113Oswego County Energy Recovery 50907_G_UNT1 Municipal Solid Waste UPNY 1.7 19338 83Oswego County Energy Recovery 50907_G_UNT2 Municipal Solid Waste UPNY 1.7 19338 83Potlatch Southern Wood Products 50640_B_BLR1 Biomass ENTG 10.0 15517 83
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Yellowstone Energy LP 50931_B_BLR1 Coal Steam NWPE 27.5 14500 111Yellowstone Energy LP 50931_B_BLR2 Coal Steam NWPE 27.5 10331 103Watsonville Power Plant 50968_G_GEN1 Combined Cycle CA‐N 22.0 11693 76Watsonville Power Plant 50968_G_GEN2 Combined Cycle CA‐N 6.9 11693 76Indiantown Cogeneration LP 50976_B_AAB01 Coal Steam FRCC 330 9200 92Pryor Power Plant 50991_G_GEN1 Combustion Turbine SPPS 17.5 12503 Retired Pryor Power Plant 50991_G_GEN2 Combustion Turbine SPPS 17.5 12503 Retired Pryor Power Plant 50991_G_GN10 O/G Steam SPPS 13.0 14789 Retired STEC‐S LLC 56079_B_North Biomass ENTG 2.0 15517 145North Shore Towers 52052_G_GEN1 IC Engine NYC 1.1 13298 87North Shore Towers 52052_G_GEN2 IC Engine NYC 1.1 13298 87North Shore Towers 52052_G_GEN3 IC Engine NYC 1.1 13298 87North Shore Towers 52052_G_GEN4 IC Engine NYC 1.1 13298 87North Shore Towers 52052_G_GEN5 IC Engine NYC 1.1 13298 87North Shore Towers 52052_G_GEN6 IC Engine NYC 1.1 13298 87Trigen Nassau Energy 52056_G_GT1 Combined Cycle LILC 43.0 7492 62Trigen Nassau Energy 52056_G_ST1 Combined Cycle LILC 12.0 7492 62Rhodia Dominguez Plant 52064_G_GEN1 O/G Steam CA‐S 3.0 11332 83Rhodia Houston Plant 52065_G_GEN1 Non‐Fossil Waste ERCT 6.0 13102 83Rhodia Houston Plant 52065_G_GEN2 Non‐Fossil Waste ERCT 1.5 13102 83McKittrick Cogen 52076_G_GEN1 Combustion Turbine CA‐N 2.9 15981 87McKittrick Cogen 52076_G_GEN2 Combustion Turbine CA‐N 2.9 15981 87McKittrick Cogen 52076_G_GEN3 Combustion Turbine CA‐N 2.9 15981 87North Midway Cogen 52078_G_GEN7 Combustion Turbine CA‐N 2.9 15981 87North Midway Cogen 52078_G_GEN8 Combustion Turbine CA‐N 2.9 15981 87North Midway Cogen 52078_G_GEN9 Combustion Turbine CA‐N 2.9 15981 87Concord Cogen 52080_G_1605 IC Engine CA‐N 1.5 13298 105Concord Cogen 52080_G_1606 IC Engine CA‐N 1.5 13298 105Cymric 31X Cogen 52081_G_TG1 Combustion Turbine CA‐N 2.7 15981 87Cymric 31X Cogen 52081_G_TG2 Combustion Turbine CA‐N 2.7 15981 87Cymric 6Z Cogen 52082_G_TG1 Combustion Turbine CA‐N 2.7 15981 87Cymric 6Z Cogen 52082_G_TG2 Combustion Turbine CA‐N 2.7 15981 87Coalinga 6C Cogen 52083_G_TG1 Combustion Turbine CA‐N 2.7 15981 87Coalinga 6C Cogen 52083_G_TG2 Combustion Turbine CA‐N 2.7 15981 87Taft 26C Cogen 52085_G_TG1 Combustion Turbine CA‐N 2.7 15981 87Taft 26C Cogen 52085_G_TG2 Combustion Turbine CA‐N 2.7 15981 87Taft 26C Cogen 52085_G_TG3 Combustion Turbine CA‐N 2.7 15981 87Taft 26C Cogen 52085_G_TG4 Combustion Turbine CA‐N 2.7 15981 87Coalinga 25D Cogen 52086_G_TG1 Combustion Turbine CA‐N 2.7 15981 87Coalinga 25D Cogen 52086_G_TG2 Combustion Turbine CA‐N 2.7 15981 87Coalinga 25D Cogen 52086_G_TG3 Combustion Turbine CA‐N 2.7 15981 87
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Coalinga 25D Cogen 52086_G_TG4 Combustion Turbine CA‐N 2.7 15981 87Texas City Power Plant 52088_G_GEN1 Combined Cycle ERCT 139 10299 63Texas City Power Plant 52088_G_GEN2 Combined Cycle ERCT 104 10299 63Texas City Power Plant 52088_G_GEN3 Combined Cycle ERCT 104 10299 63Texas City Power Plant 52088_G_GEN4 Combined Cycle ERCT 104 10299 63New York Methodist Hospital 52091_G_3A IC Engine NYC 0.70 12870 87New York Methodist Hospital 52091_G_4C IC Engine NYC 0.70 12870 87Oxford Cogeneration Facility 52093_G_GEN1 Combustion Turbine CA‐N 2.4 15981 158Oxford Cogeneration Facility 52093_G_GEN2 Combustion Turbine CA‐N 2.4 15981 158Kern River Fee

A Cogen 52094_G_GEN1 Combustion Turbine CA‐S 3.2 15981 87

Kern River Fee

A Cogen 52094_G_GEN2 Combustion Turbine CA‐S 3.2 15981 87

Kern River Fee C Cogen 52095_G_GEN1 Combustion Turbine CA‐S 3.6 15981 87Kern River Fee C Cogen 52095_G_GEN2 Combustion Turbine CA‐S 3.2 15981 87Berry Placerita Cogen 52096_G_GEN1 Combustion Turbine CA‐S 19.6 12503 87Berry Placerita Cogen 52096_G_GEN2 Combustion Turbine CA‐S 19.6 12503 87Cymric 36W Cogen 52104_G_GEN1 Combustion Turbine CA‐N 2.7 15981 87Cymric 36W Cogen 52104_G_GEN2 Combustion Turbine CA‐N 2.7 15981 87Cymric 36W Cogen 52104_G_GEN3 Combustion Turbine CA‐N 2.7 15981 87Cymric 36W Cogen 52104_G_GEN4 Combustion Turbine CA‐N 2.7 15981 87Kern River Eastridge Cogen 52107_G_101A Combustion Turbine CA‐N 21.0 15981 87Kern River Eastridge Cogen 52107_G_101B Combustion Turbine CA‐N 21.0 15981 87C P Kelco San Diego Plant 52147_G_GEN1 Combustion Turbine CA‐S 8.0 15981 87C P Kelco San Diego Plant 52147_G_GEN2 Combustion Turbine CA‐S 9.3 15981 87C P Kelco San Diego Plant 52147_G_GEN3 Combustion Turbine CA‐S 9.3 15981 87Midway Sunset Cogen 52169_G_A Combustion Turbine CA‐N 73.0 15981 87Midway Sunset Cogen 52169_G_B Combustion Turbine CA‐N 73.0 15981 87Midway Sunset Cogen 52169_G_C Combustion Turbine CA‐N 73.0 15981 87C R Wing Cogen Plant 52176_G_GEN1 Combined Cycle ERCT 76.0 8982 77C R Wing Cogen Plant 52176_G_GEN2 Combined Cycle ERCT 76.0 8982 77C R Wing Cogen Plant 52176_G_GEN3 Combined Cycle ERCT 75.0 8982 77Yuba City Cogen Partners 52186_G_GEN1 Combustion Turbine CA‐N 48.7 15256 87Delaware City Plant 52193_G_CT1 Fossil Waste MACE 101 9107 91Delaware City Plant 52193_G_CT2 Fossil Waste MACE 92.0 9107 91Delaware City Plant 52193_G_G1 Fossil Waste MACE 29.5 9107 91Delaware City Plant 52193_G_G2 Fossil Waste MACE 29.5 9107 91JRW Associates LP 52198_G_GEN1 O/G Steam CA‐N 1.1 11425 111JRW Associates LP 52198_G_GEN2 O/G Steam CA‐N 1.1 11425 111JRW Associates LP 52198_G_GEN3 IC Engine CA‐N 1.1 11600 87JRW Associates LP 52198_G_GEN4 IC Engine CA‐N 1.1 11600 87JRW Associates LP 52198_G_GEN5 IC Engine CA‐N 1.1 11600 87JRW Associates LP 52198_G_GEN6 IC Engine CA‐N 1.1 11600 87
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JRW Associates LP 52198_G_GEN7 IC Engine CA‐N 1.1 11600 87JRW Associates LP 52198_G_GEN8 IC Engine CA‐N 1.1 11600 87Ridgewood/Byron Power Partners 52199_G_GEN1 IC Engine CA‐N 1.1 13776 126Ridgewood/Byron Power Partners 52199_G_GEN2 IC Engine CA‐N 1.1 13776 126Ridgewood/Byron Power Partners 52199_G_GEN3 IC Engine CA‐N 1.1 13776 126Ridgewood/Byron Power Partners 52199_G_GEN4 IC Engine CA‐N 1.1 13776 126Ridgewood/Byron Power Partners 52199_G_GEN5 IC Engine CA‐N 1.1 13776 126Sunnyside Cogen Partners 52201_G_GEN1 IC Engine CA‐N 1.1 11303 113Sunnyside Cogen Partners 52201_G_GEN2 IC Engine CA‐N 1.1 11303 113Sunnyside Cogen Partners 52201_G_GEN3 IC Engine CA‐N 1.1 11303 113Sunnyside Cogen Partners 52201_G_GEN4 IC Engine CA‐N 1.1 11303 113Sunnyside Cogen Partners 52201_G_GEN5 IC Engine CA‐N 1.1 11303 113Pittsburg Power Plant 54001_G_GEN1 Combustion Turbine CA‐N 16.5 9939 87Pittsburg Power Plant 54001_G_GEN2 Combustion Turbine CA‐N 22.0 9939 87Pittsburg Power Plant 54001_G_GEN3 Combustion Turbine CA‐N 22.0 9939 87Westmoreland Roanoke Valley I 54035_B_BLR1 Coal Steam VAPW 165 10370 91Lockport Energy Associates LP 54041_G_GEN1 Combined Cycle UPNY 45.0 9091 74Lockport Energy Associates LP 54041_G_GEN2 Combined Cycle UPNY 45.0 9091 74Lockport Energy Associates LP 54041_G_GEN3 Combined Cycle UPNY 45.0 9091 74Lockport Energy Associates LP 54041_G_GEN4 Combined Cycle UPNY 75.2 9091 74Wythe Park Power Petersburg Plant 54045_G_1 Fossil Waste VAPW 3.0 12320 93Wythe Park Power 3 Richmond Plant 54047_G_EXIS IC Engine VAPW 3.0 12283 90Pawtucket Power Associates 54056_G_GEN1 Combined Cycle NENG 36.0 8950 89Pawtucket Power Associates 54056_G_GEN2 Combined Cycle NENG 27.0 8950 89Indeck Olean Energy Center 54076_G_GEN1 Combined Cycle UPNY 31.9 8740 86Indeck Olean Energy Center 54076_G_GEN2 Combined Cycle UPNY 44.6 8740 86Cogentrix of Richmond 54081_B_1A Coal Steam VAPW 26.3 11303 92Cogentrix of Richmond 54081_B_1B Coal Steam VAPW 26.3 10331 92Cogentrix of Richmond 54081_B_2A Coal Steam VAPW 26.3 11303 92Cogentrix of Richmond 54081_B_2B Coal Steam VAPW 26.3 10331 92Cogentrix of Richmond 54081_B_3A Coal Steam VAPW 21.3 11300 92Cogentrix of Richmond 54081_B_3B Coal Steam VAPW 21.3 10331 92Cogentrix of Richmond 54081_B_4A Coal Steam VAPW 21.3 11300 92Cogentrix of Richmond 54081_B_4B Coal Steam VAPW 21.3 10331 92Kennedy International Airport Cogen 54114_G_GEN1 Combined Cycle NYC 49.0 10315 80Kennedy International Airport Cogen 54114_G_GEN2 Combined Cycle NYC 50.3 10315 80Kennedy International Airport Cogen 54114_G_GEN3 Combined Cycle NYC 27.0 10315 80Fortistar North Tonawanda 54131_G_GEN1 Combined Cycle UPNY 40.4 7800 78Fortistar North Tonawanda 54131_G_GEN2 Combined Cycle UPNY 16.3 7800 78Fulton Cogeneration Associates 54138_G_GTG Combustion Turbine UPNY 42.0 12503 124Stony Brook Cogen Plant 54149_G_GEN1 Combustion Turbine LILC 44.5 12082 87
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Franklin Heating Station 54224_B_GEN6 Coal Steam MRO 2.8 10331 103Franklin Heating Station 54224_B_SG1 O/G Steam MRO 1 14789 83Franklin Heating Station 54224_B_SG2 O/G Steam MRO 1 14789 83Franklin Heating Station 54224_B_SG3 O/G Steam MRO 4.1 14789 83Franklin Heating Station 54224_B_SG4 O/G Steam MRO 4.1 14789 83Franklin Heating Station 54224_G_EG1 IC Engine MRO 2.0 12334 120Franklin Heating Station 54224_G_EG2 IC Engine MRO 2.0 12334 120Franklin Heating Station 54224_G_EG3 IC Engine MRO 2.0 12334 120Port of Stockton District Energy Fac 54238_B_N64514 Coal Steam CA‐N 22.0 11465 114Port of Stockton District Energy Fac 54238_B_N64516 Coal Steam CA‐N 22.0 10331 103March Point Cogeneration 54268_G_GTG1 Combined Cycle PNW 39.6 11500 60March Point Cogeneration 54268_G_GTG2 Combined Cycle PNW 40.0 11500 60March Point Cogeneration 54268_G_GTG3 Combined Cycle PNW 40.6 11500 60March Point Cogeneration 54268_G_STG1 Combined Cycle PNW 26.0 11500 60Saguaro Power 54271_G_CTG1 Combined Cycle SNV 35.0 9200 92Saguaro Power 54271_G_CTG2 Combined Cycle SNV 35.0 9200 92Saguaro Power 54271_G_STG Combined Cycle SNV 22.0 9200 92Birchwood Power 54304_B_1A Coal Steam VAPW 239 10067 96Goodyear Beaumont Chemical Plant 54321_B_3B101 O/G Steam ENTG 1.6 11425 83Goodyear Beaumont Chemical Plant 54321_B_3B102 O/G Steam ENTG 1.6 11425 83Goodyear Beaumont Chemical Plant 54321_B_3B103 O/G Steam ENTG 1.6 11425 83Goodyear Beaumont Chemical Plant 54321_B_3B104 O/G Steam ENTG 1.6 11425 83Goodyear Beaumont Chemical Plant 54321_B_3B105 O/G Steam ENTG 1.6 11425 83Goodyear Beaumont Chemical Plant 54321_B_3B106 O/G Steam ENTG 1.6 11425 83Goodyear Beaumont Chemical Plant 54321_B_3B107 O/G Steam ENTG 1.6 11425 83Goodyear Beaumont Chemical Plant 54321_B_3B108 O/G Steam ENTG 1.6 11425 83Goodyear Beaumont Chemical Plant 54321_G_2N80 Combustion Turbine ENTG 4.0 12503 87Goodyear Beaumont Chemical Plant 54321_G_N802 Combustion Turbine ENTG 4.0 12503 87Goodyear Beaumont Chemical Plant 54321_G_N803 Combustion Turbine ENTG 4.0 12503 87Goodyear Beaumont Chemical Plant 54321_G_N804 Combustion Turbine ENTG 4.0 12503 87Bucknell University 54333_G_G001 Combined Cycle MACW 4.3 7933 79Bucknell University 54333_G_G502 Combined Cycle MACW 0.50 7933 79Nevada Cogen Associates 2 Black Mountain 54349_G_GTA Combined Cycle SNV 21.7 7132 66Nevada Cogen Associates 2 Black Mountain 54349_G_GTB Combined Cycle SNV 21.7 7132 66Nevada Cogen Associates 2 Black Mountain 54349_G_GTC Combined Cycle SNV 21.7 7132 66Nevada Cogen Associates 2 Black Mountain 54349_G_STM Combined Cycle SNV 19.9 7132 66Nevada Cogen Assoc#1 GarnetVly 54350_G_GTA Combined Cycle SNV 21.7 10182 73Nevada Cogen Assoc#1 GarnetVly 54350_G_GTB Combined Cycle SNV 21.7 10182 73Nevada Cogen Assoc#1 GarnetVly 54350_G_GTC Combined Cycle SNV 21.7 10182 73Nevada Cogen Assoc#1 GarnetVly 54350_G_STM Combined Cycle SNV 19.9 10182 73Orange Cogeneration Facility 54365_G_APC1 Combined Cycle FRCC 46.4 8999 73
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Orange Cogeneration Facility 54365_G_APC2 Combined Cycle FRCC 46.4 8999 73Orange Cogeneration Facility 54365_G_APC3 Combined Cycle FRCC 24.6 8999 73Oildale Cogen 54371_G_ODC1 Combustion Turbine CA‐N 39.0 16463 87University of Colorado 54372_G_GT1 Combined Cycle RMPA 15.0 7933 71University of Colorado 54372_G_GT2 Combined Cycle RMPA 15.0 7933 71University of Colorado 54372_G_ST1 Combined Cycle RMPA 1 7933 71Southbridge Energy Center LLC 54373_G_ENG1 IC Engine NENG 1.3 11600 91Southbridge Energy Center LLC 54373_G_ENG2 IC Engine NENG 1.3 11600 91Southbridge Energy Center LLC 54373_G_ENG3 IC Engine NENG 1.3 11600 91Southbridge Energy Center LLC 54373_G_ENG4 IC Engine NENG 1.3 11600 91Southbridge Energy Center LLC 54373_G_ENG5 IC Engine NENG 1.3 11600 91Capitol Heat and Power 54406_G_1 Coal Steam WUMS 0.90 10331 83Capitol Heat and Power 54406_G_2 Coal Steam WUMS 1 10331 83DAI Oildale 54410_G_CTG Combined Cycle CA‐N 22.6 7933 79DAI Oildale 54410_G_STG Combined Cycle CA‐N 7.3 7933 79Lake Cogen Ltd 54423_G_GT1 Combined Cycle FRCC 41.5 7550 74Lake Cogen Ltd 54423_G_GT2 Combined Cycle FRCC 41.5 7550 74Lake Cogen Ltd 54423_G_ST1 Combined Cycle FRCC 27.0 7550 74Pasco Cogen Ltd 54424_G_GT1 Combined Cycle FRCC 48.8 7701 77Pasco Cogen Ltd 54424_G_GT2 Combined Cycle FRCC 48.8 7701 77Pasco Cogen Ltd 54424_G_ST1 Combined Cycle FRCC 31.2 7701 77Project Orange Associates LP 54425_G_GT1 Combustion Turbine UPNY 48.0 12503 87Project Orange Associates LP 54425_G_GT2 Combustion Turbine UPNY 48.0 12503 87Mulberry Cogeneration Facility 54426_G_GT1 Combined Cycle FRCC 76.0 8520 81Mulberry Cogeneration Facility 54426_G_ST1 Combined Cycle FRCC 37.0 8520 81Alabama Pine Pulp 54429_B_PB2 Biomass SOU 32.1 15517 83Alabama Pine Pulp 54429_B_RB2 Non‐Fossil Waste SOU 32.1 13102 83Rincon Facility 54445_G_GEN1 Combustion Turbine CA‐S 1.7 12503 Retired Welport Lease Project 54447_G_TI Combustion Turbine CA‐N 4.5 12503 88Dome Project 54449_G_T1 Combustion Turbine CA‐N 3.3 15981 87Dome Project 54449_G_T2 Combustion Turbine CA‐N 3.2 15981 87Orlando Cogen LP 54466_G_GEN1 Combined Cycle FRCC 120 9960 78Sumas Power Plant 54476_G_GEN1 Combined Cycle PNW 87.8 8120 72Sumas Power Plant 54476_G_GEN2 Combined Cycle PNW 37.7 8120 72Oroville Cogeneration LP 54477_G_GEN1 IC Engine CA‐N 1.1 11600 111Oroville Cogeneration LP 54477_G_GEN2 IC Engine CA‐N 1.1 11600 111Oroville Cogeneration LP 54477_G_GEN3 IC Engine CA‐N 1.1 11600 111Oroville Cogeneration LP 54477_G_GEN4 IC Engine CA‐N 1.1 11600 111Oroville Cogeneration LP 54477_G_GEN5 IC Engine CA‐N 1.1 11600 111Oroville Cogeneration LP 54477_G_GEN6 IC Engine CA‐N 1.1 11600 111Oroville Cogeneration LP 54477_G_GEN7 IC Engine CA‐N 1.1 11600 111
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STEC‐S LLC 56079_B_South Biomass ENTG 2.0 15517 145Formosa Plastics 54518_G_GT1 Combined Cycle ENTG 33.0 8648 Retired Formosa Plastics 54518_G_GT2 Combined Cycle ENTG 33.0 8648 85Formosa Plastics 54518_G_GT3 Combined Cycle ENTG 33.0 8648 85Formosa Plastics 54518_G_ST1 Combined Cycle ENTG 8.0 8648 85Formosa Plastics 54518_G_ST2 Combined Cycle ENTG 8.0 8648 85Lyonsdale Biomass LLC 54526_B_00001 Biomass UPNY 19.0 15517 132Tenaska Ferndale Cogeneration Station 54537_G_CT1A Combined Cycle PNW 88.0 11260 75Tenaska Ferndale Cogeneration Station 54537_G_CT1B Combined Cycle PNW 88.0 11260 75Tenaska Ferndale Cogeneration Station 54537_G_ST1 Combined Cycle PNW 95.0 11260 75Entenmanns Energy Center 54541_G_1 IC Engine LILC 1.3 12703 87Entenmanns Energy Center 54541_G_2 IC Engine LILC 1.3 12703 87Entenmanns Energy Center 54541_G_3 IC Engine LILC 1.3 12703 87Entenmanns Energy Center 54541_G_4 IC Engine LILC 1.3 12784 87Sithe Independence Station 54547_G_1 Combined Cycle UPNY 144 7418 69Sithe Independence Station 54547_G_2 Combined Cycle UPNY 144 7418 69Sithe Independence Station 54547_G_3 Combined Cycle UPNY 144 7418 69Sithe Independence Station 54547_G_4 Combined Cycle UPNY 144 7418 69Sithe Independence Station 54547_G_5 Combined Cycle UPNY 204 7418 69Sithe Independence Station 54547_G_6 Combined Cycle UPNY 204 7418 69ExxonMobil Mobile Bay Onshore 54550_G_901 Combined Cycle SOU 0.90 7933 79ExxonMobil Mobile Bay Onshore 54550_G_901A Combined Cycle SOU 3.4 7933 79ExxonMobil Mobile Bay Onshore 54550_G_901B Combined Cycle SOU 3.4 7933 79ExxonMobil Mobile Bay Onshore 54550_G_901C Combined Cycle SOU 3.4 7933 79Jefferson Smurfit Santa Clara Mill 54561_G_GT‐G Combined Cycle CA‐N 23.0 9780 57Jefferson Smurfit Santa Clara Mill 54561_G_ST‐G Combined Cycle CA‐N 3.0 9780 57North East Cogeneration Plant 54571_G_GEN1 Combined Cycle MACW 36.5 9163 67North East Cogeneration Plant 54571_G_GEN2 Combined Cycle MACW 36.5 9163 67North East Cogeneration Plant 54571_G_GEN3 Combined Cycle MACW 8.0 9163 67Saranac Facility 54574_G_GEN1 Combined Cycle UPNY 78.0 8616 73Saranac Facility 54574_G_GEN2 Combined Cycle UPNY 77.0 8616 73Saranac Facility 54574_G_GEN3 Combined Cycle UPNY 85.0 8616 73Glenns Ferry Cogen Facility 54578_G_1001 Combined Cycle PNW 10.4 9800 84Rupert Cogen Project 54579_G_1002 Combined Cycle NWPE 10.4 9800 63Batavia Power Plant 54593_G_GEN1 Combined Cycle UPNY 38.2 8771 74Batavia Power Plant 54593_G_GEN2 Combined Cycle UPNY 17.5 8771 74Mt Poso Cogeneration 54626_B_BL01 Coal Steam CA‐N 52.0 11384 112Okeelanta Cogeneration 54627_B_A Biomass FRCC 25.0 15517 89Okeelanta Cogeneration 54627_B_B Biomass FRCC 25.0 15517 89Okeelanta Cogeneration 54627_B_C Biomass FRCC 25.0 15517 89Okeelanta Cogeneration 54627_G_GEN2 Biomass FRCC 74.9 15517 89
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St Nicholas Cogen Project 54634_B_1 Coal Steam MACW 87.9 10931 109JCO Oxides Olefins Plant 54637_G_GCG1 Combustion Turbine ENTG 30.5 12503 87JCO Oxides Olefins Plant 54637_G_GCG2 Combustion Turbine ENTG 30.5 12503 87Lakewood Cogen LP 54640_G_GEN1 Combined Cycle MACE 78.0 8129 81Lakewood Cogen LP 54640_G_GEN2 Combined Cycle MACE 78.0 8129 81Lakewood Cogen LP 54640_G_NA Combined Cycle MACE 83.0 8129 81Auburndale Power Partners 54658_G_CT Combined Cycle FRCC 105 8900 83Auburndale Power Partners 54658_G_ST Combined Cycle FRCC 49.6 8900 83Oyster Creek Unit VIII 54676_G_G81 Combined Cycle ERCT 73.0 10000 96Oyster Creek Unit VIII 54676_G_G82 Combined Cycle ERCT 73.0 10000 96Oyster Creek Unit VIII 54676_G_G83 Combined Cycle ERCT 73.0 10000 96Oyster Creek Unit VIII 54676_G_G84 Combined Cycle ERCT 160 10000 96CII Carbon LLC 54677_B_HRB Coal Steam ENTG 23.0 10331 103CII Carbon LLC 54677_G_TG‐2 Coal Steam ENTG 23.0 10331 103York Cogen Facility 54693_G_GT#1 Combined Cycle MACW 6.9 9830 98York Cogen Facility 54693_G_GT#2 Combined Cycle MACW 6.6 9830 98York Cogen Facility 54693_G_GT#5 Combined Cycle MACW 6.9 9830 98York Cogen Facility 54693_G_GT#6 Combined Cycle MACW 6.1 9830 98York Cogen Facility 54693_G_ST#1 Combined Cycle MACW 7.2 9830 98York Cogen Facility 54693_G_ST#2 Combined Cycle MACW 6.9 9830 98Yuma Cogeneration Associates 54694_G_GEN1 Combined Cycle AZNM 35.1 8971 76Yuma Cogeneration Associates 54694_G_GEN2 Combined Cycle AZNM 17.1 8971 76Hunterdon Cogen Facility 54707_G_1 Combustion Turbine MACE 4.1 12503 87Montclair Cogen Facility 54708_G_1 Combustion Turbine MACE 3.7 12503 87Port Neches Plant 54748_G_G1 Combustion Turbine ENTG 32.0 12503 87Goal Line LP 54749_G_CTG Combined Cycle CA‐S 40.0 9182 77Goal Line LP 54749_G_STG Combined Cycle CA‐S 9.4 9182 77Westmoreland Roanoke Valley II 54755_B_BLR2 Coal Steam VAPW 44.0 11346 95Hermiston Generating Plant 54761_G_GEN1 Combined Cycle PNW 80.0 11182 73Hermiston Generating Plant 54761_G_GEN2 Combined Cycle PNW 152 11182 73Hermiston Generating Plant 54761_G_GEN3 Combined Cycle PNW 80.0 11182 73Hermiston Generating Plant 54761_G_GEN4 Combined Cycle PNW 152 11182 73Boydton Plank Road Cogen Plant 54766_G_GEN1 Fossil Waste VAPW 3.0 11036 110Live Oak Cogen 54768_G_GEN1 Combustion Turbine CA‐N 46.0 15065 87University of Iowa Main Power Plant 54775_B_BLR10 Coal Steam MRO 4.2 12508 83University of Iowa Main Power Plant 54775_B_BLR11 Coal Steam MRO 4.2 12508 83University of Iowa Main Power Plant 54775_B_BLR7 O/G Steam MRO 4.2 14789 83University of Iowa Main Power Plant 54775_B_BLR8 O/G Steam MRO 4.2 14789 83University of Iowa Main Power Plant 54775_B_BLR9 O/G Steam MRO 4.2 14789 83Grays Ferry Cogeneration 54785_G_GEN1 Combined Cycle MACE 50.0 9033 55Grays Ferry Cogeneration 54785_G_GEN2 Combined Cycle MACE 100 9033 55
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Plymouth State College Cogeneration 54803_G_A IC Engine NENG 1.2 12334 94Milagro Cogeneration Plant 54814_G_GENA Combustion Turbine AZNM 30.4 16541 87Milagro Cogeneration Plant 54814_G_GENB Combustion Turbine AZNM 30.4 16541 87Milagro Cogeneration Plant 54814_G_GO1A Combustion Turbine AZNM 30.4 16521 87Milagro Cogeneration Plant 54814_G_GO1B Combustion Turbine AZNM 30.4 16541 87Johnson County 54817_G_GT‐1 Combined Cycle ERCT 163 7060 78Johnson County 54817_G_ST‐1 Fossil Waste ERCT 104 7859 78Panda Brandywine LP 54832_G_1 Combined Cycle MACS 78.6 8330 76Panda Brandywine LP 54832_G_2 Combined Cycle MACS 78.6 8330 76Panda Brandywine LP 54832_G_3 Combined Cycle MACS 72.8 8330 76Outagamie County Co‐Generation Facility 54842_G_GEN1 Landfill Gas WUMS 0.80 13682 92Gordonsville Energy LP 54844_G_GOR1 Combined Cycle VAPW 71.4 8593 87Gordonsville Energy LP 54844_G_GOR2 Combined Cycle VAPW 71.4 8593 87Gordonsville Energy LP 54844_G_GOR3 Combined Cycle VAPW 40.6 8593 87Gordonsville Energy LP 54844_G_GOR4 Combined Cycle VAPW 40.6 8593 87Cox Waste to Energy 54850_G_01 Biomass TVAK 3.0 15517 83Cox Waste to Energy 54850_G_02 Biomass TVAK 0.30 15517 83Brooklyn Navy Yard Cogeneration 54914_G_01 Combined Cycle NYC 85.0 7477 67Brooklyn Navy Yard Cogeneration 54914_G_02 Combined Cycle NYC 85.0 7477 67Brooklyn Navy Yard Cogeneration 54914_G_03 Combined Cycle NYC 30.0 7477 67Brooklyn Navy Yard Cogeneration 54914_G_04 Combined Cycle NYC 30.0 7477 67Michigan Power LP 54915_G_G001 Combined Cycle MECS 58.0 10880 93Michigan Power LP 54915_G_G101 Combined Cycle MECS 70.0 10880 93Sauder Power Plant 54974_G_UNT1 Biomass RFCO 3.6 18060 180Sauder Power Plant 54974_G_UNT2 Biomass RFCO 3.6 18060 180Fellsway Development LLC 54992_G_CAT1 IC Engine NENG 0.70 13123 97Fellsway Development LLC 54992_G_CAT2 IC Engine NENG 0.80 13123 97Fellsway Development LLC 54992_G_GT Combustion Turbine NENG 0.60 15981 97Fellsway Development LLC 54992_G_ST Coal Steam NENG 0.20 13754 103SPSA Waste To Energy Power Plant 54998_B_12300 Municipal Solid Waste VAPW 11.6 19338 125SPSA Waste To Energy Power Plant 54998_B_12400 Municipal Solid Waste VAPW 11.6 19338 125SPSA Waste To Energy Power Plant 54998_B_12500 Municipal Solid Waste VAPW 11.6 19338 125SPSA Waste To Energy Power Plant 54998_B_12600 Municipal Solid Waste VAPW 11.6 19338 125LSP‐Cottage Grove LP 55010_G_CTG1 Combined Cycle MRO 154 7745 72LSP‐Cottage Grove LP 55010_G_STG1 Combined Cycle MRO 97.0 7745 72LSP‐Whitewater LP 55011_G_CTG1 Combined Cycle WUMS 156 7739 66LSP‐Whitewater LP 55011_G_STG1 Combined Cycle WUMS 97.0 7739 66Sweeny Cogen Facility 55015_G_1 Combustion Turbine ERCT 115 11707 117Sweeny Cogen Facility 55015_G_2 Combustion Turbine ERCT 115 11707 117Sweeny Cogen Facility 55015_G_3 Combustion Turbine ERCT 115 11707 117Sweeny Cogen Facility 55015_G_4 Combustion Turbine ERCT 115 11707 117
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J & L Electric 55034_G_0001 Biomass NENG 0.35 15517 157J & L Electric 55034_G_0002 Biomass NENG 0.50 15517 157Mid‐Georgia Cogeneration Facility 55040_G_CT1 Combined Cycle SOU 107 7950 68Mid‐Georgia Cogeneration Facility 55040_G_CT2 Combined Cycle SOU 107 7950 68Mid‐Georgia Cogeneration Facility 55040_G_ST1 Combined Cycle SOU 103 7950 68Cherokee County Cogen 55043_G_GT1 Combined Cycle VACA 80.0 8000 86Cherokee County Cogen 55043_G_ST1 Combined Cycle VACA 35.0 8000 86Pasadena Cogeneration 55047_G_CTG1 Combined Cycle ERCT 155 7200 67Pasadena Cogeneration 55047_G_CTG2 Combined Cycle ERCT 165 7200 67Pasadena Cogeneration 55047_G_CTG3 Combined Cycle ERCT 165 7200 67Pasadena Cogeneration 55047_G_STG1 Combined Cycle ERCT 50.0 7200 67Pasadena Cogeneration 55047_G_STG2 Combined Cycle ERCT 165 7200 67Tamarack Energy Partnership 50099_G_GEN1 Biomass PNW 5.8 15943 145Georgia Gulf Plaquemine 55051_G_X773 Combustion Turbine ENTG 80.0 12435 87Georgia Gulf Plaquemine 55051_G_X774 Combustion Turbine ENTG 80.0 12435 87Georgia Gulf Plaquemine 55051_G_X775 Combustion Turbine ENTG 80.0 12435 87Black Hawk Station 55064_G_UNT1 Combustion Turbine SPPS 111 13188 88Black Hawk Station 55064_G_UNT2 Combustion Turbine SPPS 111 13200 88Pine Bluff Energy Center 55075_G_CT01 Combined Cycle ENTG 150 7274 55Pine Bluff Energy Center 55075_G_ST01 Combined Cycle ENTG 48.0 7274 55Crockett Cogen Project 55084_G_GE1 Combined Cycle CA‐N 247 7500 59Gregory Power Facility 55086_G_GT1A Combined Cycle ERCT 156 7274 55Gregory Power Facility 55086_G_GT1B Combined Cycle ERCT 156 7274 55Gregory Power Facility 55086_G_STG Combined Cycle ERCT 100 7274 55Dearborn Industrial Generation 55088_G_GT 1 Combined Cycle MECS 150 7274 55Dearborn Industrial Generation 55088_G_GT2 Combined Cycle MECS 150 7274 55Dearborn Industrial Generation 55088_G_GTP1 Combined Cycle MECS 150 7274 55Dearborn Industrial Generation 55088_G_ST1 Combined Cycle MECS 250 7274 55Taft Cogeneration Facility 55089_G_CT1 Combined Cycle ENTG 155 7933 73Taft Cogeneration Facility 55089_G_CT2 Combined Cycle ENTG 155 7933 73Taft Cogeneration Facility 55089_G_CT3 Combined Cycle ENTG 155 7933 73Taft Cogeneration Facility 55089_G_ST1 Combined Cycle ENTG 325 7933 73Plummer Forest Products 55090_G_GEN1 Biomass PNW 5.8 16912 100Miramar Landfill Metro Biosolids Center 55094_G_UNT1 Landfill Gas CA‐S 1.6 11855 128Miramar Landfill Metro Biosolids Center 55094_G_UNT2 Landfill Gas CA‐S 1.6 11855 128Miramar Landfill Metro Biosolids Center 55094_G_UNT3 Landfill Gas CA‐S 1.6 11855 128Miramar Landfill Metro Biosolids Center 55094_G_UNT4 Landfill Gas CA‐S 1.6 11855 128Portside Energy 55096_G_GT Combined Cycle RFCO 34.0 6920 69Portside Energy 55096_G_ST Combined Cycle RFCO 10.0 6920 69Klamath Cogeneration Plant 55103_G_CT1 Combined Cycle PNW 150 6920 67Klamath Cogeneration Plant 55103_G_CT2 Combined Cycle PNW 150 6920 67
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Klamath Cogeneration Plant 55103_G_ST1 Combined Cycle PNW 170 6920 67Sabine Cogen 55104_G_SAB1 Combined Cycle ENTG 37.0 7274 92Sabine Cogen 55104_G_SAB2 Combined Cycle ENTG 37.0 7274 92Sabine Cogen 55104_G_STG Combined Cycle ENTG 27.0 7274 92RS Cogen 55117_G_RS‐4 Combined Cycle ENTG 60.2 7933 79RS Cogen 55117_G_RS‐5 Combined Cycle ENTG 168 7933 79RS Cogen 55117_G_RS‐6 Combined Cycle ENTG 168 7933 79SRW Cogen LP 55120_G_GT1A Combined Cycle ENTG 160 7274 77SRW Cogen LP 55120_G_GT1B Combined Cycle ENTG 160 7274 77SRW Cogen LP 55120_G_ST1A Combined Cycle ENTG 100 7274 77NAFTA Region Olefins Complex Cogen Fac 55122_G_UN1 Combustion Turbine ENTG 35.0 12503 99NAFTA Region Olefins Complex Cogen Fac 55122_G_UN2 Combustion Turbine ENTG 35.0 12503 99Eastman Cogeneration Facility 55176_G_GEN1 Combined Cycle SPPS 146 7274 62Eastman Cogeneration Facility 55176_G_GEN2 Combined Cycle SPPS 146 7274 62Eastman Cogeneration Facility 55176_G_GEN3 Combined Cycle SPPS 110 7274 62Channelview 55187_G_CHV1 Combined Cycle ERCT 161 10457 99Channelview 55187_G_CHV2 Combined Cycle ERCT 161 10457 99Channelview 55187_G_CHV3 Combined Cycle ERCT 161 10457 99Channelview 55187_G_CHV4 Combined Cycle ERCT 161 10457 99Channelview 55187_G_ST1 Combined Cycle ERCT 135 10457 99Corpus Christi Energy Center 55206_G_CT1 Combined Cycle 162 Not in dB 75Corpus Christi Energy Center 55206_G_CT2 Combined Cycle 162 Not in dB 75Corpus Christi Energy Center 55206_G_ST1 Combined Cycle 159 Not in dB 75Aera South Belridge Cogen Facility 55216_G_STG1 Combined Cycle COMD 62.0 10244 58Aera South Belridge Cogen Facility 55216_G_UNT1 Combined Cycle COMD 38.0 10244 58Aera South Belridge Cogen Facility 55216_G_UNT2 Combined Cycle COMD 38.0 10244 58Aera South Belridge Cogen Facility 55216_G_UNT3 Combined Cycle COMD 38.0 10244 58Los Medanos Energy Center 55217_G_CTG1 Combined Cycle CA‐N 165 6920 66Los Medanos Energy Center 55217_G_CTG2 Combined Cycle CA‐N 165 6920 66Los Medanos Energy Center 55217_G_STG3 Combined Cycle CA‐N 237 6920 66Ina Road Water Pollution Control Fac 55257_G_1 IC Engine AZNM 0.59 13298 87Ina Road Water Pollution Control Fac 55257_G_2 IC Engine AZNM 0.59 13298 87Ina Road Water Pollution Control Fac 55257_G_3 IC Engine AZNM 0.59 13298 87Ina Road Water Pollution Control Fac 55257_G_4 IC Engine AZNM 0.59 13298 87Ina Road Water Pollution Control Fac 55257_G_5 IC Engine AZNM 0.59 13298 87Ina Road Water Pollution Control Fac 55257_G_6 IC Engine AZNM 0.59 13298 87Ina Road Water Pollution Control Fac 55257_G_7 IC Engine AZNM 0.59 13298 87Whiting Clean Energy 55259_G_CT1 Combined Cycle RFCO 167 7113 90Whiting Clean Energy 55259_G_CT2 Combined Cycle RFCO 167 7113 90Whiting Clean Energy 55259_G_ST1 Combined Cycle RFCO 213 7113 90Decatur Energy Center 55292_G_CTG1 Combined Cycle TVA 155 7274 99
30 

Decatur Energy Center 55292_G_CTG2 Combined Cycle TVA 155 7274 99Decatur Energy Center 55292_G_CTG3 Combined Cycle TVA 155 7274 99Decatur Energy Center 55292_G_STG1 Combined Cycle TVA 159 7274 99Morgan Energy Center 55293_G_CTG1 Combined Cycle TVA 161 7355 74Morgan Energy Center 55293_G_CTG2 Combined Cycle TVA 161 7355 74Morgan Energy Center 55293_G_CTG3 Combined Cycle TVA 161 7355 74Morgan Energy Center 55293_G_STG1 Combined Cycle TVA 266 7355 74Channel Energy Center 55299_G_CTG1 Combined Cycle ERCT 185 7200 60Channel Energy Center 55299_G_CTG2 Combined Cycle ERCT 185 7200 60Channel Energy Center 55299_G_ST‐1 Combined Cycle ERCT 215 7200 60Calvert City 55308_G_GEN1 Combustion Turbine TVA 23.0 12503 87Air Products Port Arthur 55309_G_GEN1 Combined Cycle ENTG 33.2 7274 107Air Products Port Arthur 55309_G_GEN2 Combined Cycle ENTG 3.0 7274 107Ingleside Cogeneration 55313_G_CTG1 Combined Cycle ERCT 155 7933 84Ingleside Cogeneration 55313_G_CTG2 Combined Cycle ERCT 155 7933 84Ingleside Cogeneration 55313_G_STG Combined Cycle ERCT 150 7933 84Chuck Lenzie Generating Station 55322_G_CTG1 Combined Cycle SNV 134 7031 77Chuck Lenzie Generating Station 55322_G_CTG2 Combined Cycle SNV 168 7031 77Chuck Lenzie Generating Station 55322_G_ST1 Combined Cycle SNV 184 7031 77Baytown Energy Center 55327_G_CTG1 Combined Cycle ERCT 170 7274 74Baytown Energy Center 55327_G_CTG2 Combined Cycle ERCT 170 7274 74Baytown Energy Center 55327_G_CTG3 Combined Cycle ERCT 170 7274 74Baytown Energy Center 55327_G_STG1 Combined Cycle ERCT 275 7274 74Columbia Energy Center 55386_G_CT1 Combined Cycle 157 Not in dB 64Columbia Energy Center 55386_G_CT2 Combined Cycle 157 Not in dB 64Columbia Energy Center 55386_G_ST1 Combined Cycle 151 Not in dB 64Carville Energy LLC 55404_G_CTG1 Combined Cycle ENTG 180 7274 59Carville Energy LLC 55404_G_CTG2 Combined Cycle ENTG 180 7274 59Carville Energy LLC 55404_G_STG Combined Cycle ENTG 140 7274 59Plaquemine Cogeneration Plant 55419_G_G500 Combined Cycle ENTG 169 7274 63Plaquemine Cogeneration Plant 55419_G_G600 Combined Cycle ENTG 169 7274 63Plaquemine Cogeneration Plant 55419_G_G700 Combined Cycle ENTG 169 7274 63Plaquemine Cogeneration Plant 55419_G_G800 Combined Cycle ENTG 169 7274 63Plaquemine Cogeneration Plant 55419_G_ST5 Combined Cycle ENTG 168 7274 63Deer Park Energy Center 55464_G_CTG1 Combined Cycle ERCT 155 7274 57Deer Park Energy Center 55464_G_CTG2 Combined Cycle ERCT 155 7274 57Deer Park Energy Center 55464_G_CTG3 Combined Cycle ERCT 155 7274 57Deer Park Energy Center 55464_G_CTG4 Combined Cycle ERCT 155 7274 57Deer Park Energy Center 55464_G_STG1 Combined Cycle ERCT 258 7274 57Green Power 2 55470_G_ST1 Combined Cycle ERCT 110 7933 55Green Power 2 55470_G_TR1 Combined Cycle ERCT 158 7933 55
31 

Green Power 2 55470_G_TR2 Combined Cycle ERCT 158 7933 55Green Power 2 55470_G_TR3 Combined Cycle ERCT 158 7933 55Blackburn Landfill Co‐Generation 55488_G_BB1 Landfill Gas VACA 1 12328 87Blackburn Landfill Co‐Generation 55488_G_BB2 Landfill Gas VACA 1 12328 87Blackburn Landfill Co‐Generation 55488_G_BB3 Landfill Gas VACA 0.90 12328 87Wilmington Hydrogen Plant 55557_G_T101 O/G Steam CA‐S 23.0 11425 98Combined Locks Energy Center 55558_G_GEN1 Combined Cycle WUMS 40.8 7933 62Combined Locks Energy Center 55558_G_GEN2 Combined Cycle WUMS 4.3 7933 62Binghamton Cogen 55600_G_1 Combustion Turbine UPNY 42.0 10894 93Mingo Junction Energy Center 55611_B_BOIL1 O/G Steam RFCO 7.5 11425 83Mingo Junction Energy Center 55611_B_BOIL2 O/G Steam RFCO 7.5 11425 83Mingo Junction Energy Center 55611_B_BOIL3 O/G Steam RFCO 7.5 11425 83Mingo Junction Energy Center 55611_B_BOIL4 O/G Steam RFCO 7.5 11425 83FPL Energy Marcus Hook LP 55801_G_CT13 Combined Cycle MACE 162 7274 72FPL Energy Marcus Hook LP 55801_G_CT1A Combined Cycle MACE 162 7274 72FPL Energy Marcus Hook LP 55801_G_CTIB Combined Cycle MACE 160 7274 72FPL Energy Marcus Hook LP 55801_G_STG Combined Cycle MACE 234 7274 72Desert Power LP 55858_G_GEN7 Coal Steam NWPE 40.0 9650 Retired Co‐Gen LLC 50921_G_GEN1 Biomass PNW 7.0 17974 85Ashtabula 55990_G_1 Combined Cycle RFCO 4.4 7274 70Ashtabula 55990_G_2 Combined Cycle RFCO 4.4 7274 70Ashtabula 55990_G_3 Combined Cycle RFCO 4.4 7274 70Ashtabula 55990_G_4 Combined Cycle RFCO 4.4 7274 70Ashtabula 55990_G_5 Combined Cycle RFCO 4.4 7274 70Ashtabula 55990_G_6 Combined Cycle RFCO 0.69 7274 70Ashtabula 55990_G_7 Combined Cycle RFCO 0.69 7274 70Trigen Revere 55999_G_GEN1 IC Engine NENG 2.8 10850 97Trigen Revere 55999_G_GEN2 IC Engine NENG 2.8 10850 97WWTP Power Generation Station 56036_G_GEN1 Non‐Fossil Waste CA‐N 2.0 14653 146WWTP Power Generation Station 56036_G_GEN2 Non‐Fossil Waste CA‐N 2.0 14653 146WWTP Power Generation Station 56036_G_GEN3 Non‐Fossil Waste CA‐N 2.0 14653 146Fox Valley Energy Center 56037_G_1 Coal Steam WUMS 6.5 10331 83UMCP CHP Plant 56038_G_1 Combined Cycle MACS 9.4 7933 65UMCP CHP Plant 56038_G_2 Combined Cycle MACS 9.4 7933 65UMCP CHP Plant 56038_G_3 Combined Cycle MACS 2.0 7933 65Millennium Hawkins Point 56045_G_1A Combined Cycle MACS 1.1 7933 134Millennium Hawkins Point 56045_G_1B Combined Cycle MACS 1.1 7933 134Millennium Hawkins Point 56045_G_2A Combined Cycle MACS 1.1 7933 134Millennium Hawkins Point 56045_G_2B Combined Cycle MACS 1.1 7933 134Millennium Hawkins Point 56045_G_3A Combined Cycle MACS 1.1 7933 134Millennium Hawkins Point 56045_G_3B Combined Cycle MACS 1.1 7933 134
32 

Millennium Hawkins Point 56045_G_ST1 Combined Cycle MACS 0.50 7933 134Co‐Gen II LLC 50993_G_GEN1 Biomass PNW 7.0 17139 102Sierra Pacific Aberdeen 55882_B_BLR1 Biomass PNW 16.5 15517 83Middlesex Generating Facility 56119_G_100 Non‐Fossil Waste 4.10 Not in dB 72Middlesex Generating Facility 56119_G_200 Non‐Fossil Waste 4.10 Not in dB 72Middlesex Generating Facility 56119_G_300 Non‐Fossil Waste 10.6 Not in dB 72SP Newsprint‐ Newberg Cogen 56124_B_10BLR O/G Steam PNW 22.3 11332 115SP Newsprint‐ Newberg Cogen 56124_G_GT1 Combustion Turbine PNW 41.6 12503 Retired SP Newsprint‐ Newberg Cogen 56124_G_GT2 Combustion Turbine PNW 41.6 12503 Retired Macon Energy Center 56127_G_1 Combustion Turbine GWAY 9.1 13301 133Groveton Paper Board 56140_G_TUR1 Combustion Turbine NENG 4.0 12678 124Groveton Paper Board 56140_G_TUR2 Combustion Turbine NENG 4.0 12678 124Freeport Energy Center 56152_G_CTG1 Combined Cycle 180 Not in dB 79Freeport Energy Center 56152_G_STG1 Combined Cycle 80.0 Not in dB 79Freehold Asbury Park Press 56169_G_UNT1 IC Engine MACE 1.1 11797 100Freehold Asbury Park Press 56169_G_UNT2 IC Engine MACE 1.1 11797 100Cogeneration 1 56229_G_CT1 Combined Cycle AZNM 8.3 7933 79Perham Incinerator 56243_G_1 Municipal Solid Waste MRO 1.2 19338 162Shell Chemical 56248_G_101G Combustion Turbine ENTG 32.0 12503 109Shell Chemical 56248_G_201G Combustion Turbine ENTG 32.0 12503 109Trigen St.Louis 56309_G_CT‐1 Combined Cycle GWAY 4.0 11985 55Trigen St.Louis 56309_G_CT‐2 Combined Cycle GWAY 4.2 11985 55Trigen St.Louis 56309_G_ST‐3 O/G Steam GWAY 18.0 11425 111Trigen St.Louis 56309_G_ST‐4 Combined Cycle GWAY 0.77 11985 55Trigen St.Louis 56309_G_ST‐5 Combined Cycle GWAY 0.81 11985 55Clearwater Power Plant 56356_G_CT1 Combined Cycle CA‐S 21.0 9100 93Clearwater Power Plant 56356_G_ST1 Combined Cycle CA‐S 7.0 9100 93Domain Plant 56373_G_DOMG1 Combustion Turbine ERCT 5.0 11862 118Robert Mueller Energy Center 56374_G_CT1 Combustion Turbine ERCT 3.7 12503 99Sierra Pacific Burlington Facility 56406_G_GEN1 Biomass PNW 25.0 15517 126Tesoro SLC Cogeneration Plant 56509_G_1 Combustion Turbine NWPE 11.0 12503 87Tesoro SLC Cogeneration Plant 56509_G_2 Combustion Turbine NWPE 11.0 12503 87Edge Moor 593_B_3 Coal Steam MACE 86.0 13668 127Edge Moor 593_B_4 Coal Steam MACE 174 9569 95Sherburne County 6090_B_1 Coal Steam MRO 762 10611 106Sherburne County 6090_B_2 Coal Steam MRO 752 10452 104Big Stone 6098_B_1 Coal Steam MRO 470 11609 116Warrick 6705_B_1 Coal Steam RFCO 136 10986 109Warrick 6705_B_2 Coal Steam RFCO 136 11017 110Warrick 6705_B_3 Coal Steam RFCO 136 11056 110Warrick 6705_B_4 Coal Steam RFCO 300 10418 104
33 

Gadsden 7_B_1 Coal Steam SOU 64.0 12376 123Gadsden 7_B_2 Coal Steam SOU 66.0 12846 128Whitehead 7028_G_K1 IC Engine NWPE 5.9 14151 141Whitehead 7028_G_K2 IC Engine NWPE 6.0 10069 100Whitehead 7028_G_K3 IC Engine NWPE 5.9 10069 100Whitehead 7028_G_K4 IC Engine NWPE 4.0 10069 100Whitehead 7028_G_K5 IC Engine NWPE 2.0 10746 107Whitehead 7028_G_K6 IC Engine NWPE 2.1 10746 107Whitehead 7028_G_K7 IC Engine NWPE 2.1 10746 107Brandon Station 7131_G_1 Combustion Turbine SPPS 20.0 12503 125Richard Gorsuch 7286_B_1 Coal Steam RFCO 50.0 11084 110Richard Gorsuch 7286_B_2 Coal Steam RFCO 50.0 11084 110Richard Gorsuch 7286_B_3 Coal Steam RFCO 50.0 11071 110Richard Gorsuch 7286_B_4 Coal Steam RFCO 50.0 11071 110George Neal South 7343_B_4 Coal Steam MRO 632 10470 104University of Florida 7345_G_P1 Combustion Turbine FRCC 45.0 9249 92Coyote Springs 7350_G_1 Combined Cycle PNW 142 7337 75Coyote Springs 7350_G_2 Combined Cycle PNW 71.3 7337 75Indian Trails Cogen 1 7384_B_1 O/G Steam GWAY 3.3 11425 111Indian Trails Cogen 1 7384_B_2 O/G Steam GWAY 3.3 11425 111Indian Trails Cogen 1 7384_B_3 O/G Steam GWAY 3.3 11425 111Carson Ice‐Gen Project 7527_G_1 Combined Cycle CA‐N 41.2 11860 83Carson Ice‐Gen Project 7527_G_2 Combined Cycle CA‐N 16.6 11860 83Milwaukee County 7549_B_1 Coal Steam WUMS 3.3 11704 117Milwaukee County 7549_B_2 Coal Steam WUMS 3.3 10331 103Milwaukee County 7549_B_3 Coal Steam WUMS 3.3 10331 103SCA Cogen 2 7551_G_CCST Combined Cycle CA‐N 37.6 11094 84SCA Cogen 2 7551_G_CT1A Combined Cycle CA‐N 39.6 11094 84SCA Cogen 2 7551_G_CT1B Combined Cycle CA‐N 39.6 11094 84SCA Cogen 2 7551_G_CT1C Combined Cycle 45.7 Not in dB 84SPA Cogen 3 7552_G_CCCT Combined Cycle CA‐N 111 8394 81SPA Cogen 3 7552_G_CCST Combined Cycle CA‐N 53.0 8394 81Everett Cogen 7627_B_14 Biomass PNW 36.0 15517 118US DOE Savannah River Site (D Area) 7652_B_D‐1 Coal Steam 19.6 Not in dB 103US DOE Savannah River Site (D Area) 7652_B_D‐2 Coal Steam 19.6 Not in dB 103US DOE Savannah River Site (D Area) 7652_B_D‐3 Coal Steam 19.6 Not in dB 103US DOE Savannah River Site (D Area) 7652_B_D‐4 Coal Steam 19.6 Not in dB 103Washington County Cogeneration Facility 7697_G_1 Combined Cycle SOU 80.0 7274 90Washington County Cogeneration Facility 7697_G_2 Combined Cycle SOU 22.0 7274 90General Electric Plastic 7698_G_1 Combined Cycle SOU 85.0 7274 119General Electric Plastic 7698_G_2 Combined Cycle SOU 12.0 7274 119
34 

Fairless Hills 7701_B_4 Landfill Gas MACE 30.0 13682 127Fairless Hills 7701_B_5 Landfill Gas MACE 30.0 13682 127Pea Ridge 7715_G_1 Combustion Turbine SOU 4.0 14111 141Pea Ridge 7715_G_2 Combustion Turbine SOU 4.0 11210 112Pea Ridge 7715_G_3 Combustion Turbine SOU 4.0 11210 112Theodore Cogen Facility 7721_G_1 Combined Cycle SOU 152 7274 70Theodore Cogen Facility 7721_G_2 Combined Cycle SOU 36.0 7274 70Cogen South 7737_B_B001 Coal Steam VACA 90.0 10966 109Encogen 7870_G_CTG1 Combined Cycle PNW 39.4 11200 91Encogen 7870_G_CTG2 Combined Cycle PNW 39.4 11200 91Encogen 7870_G_CTG3 Combined Cycle PNW 39.4 11200 91Encogen 7870_G_STG Combined Cycle PNW 51.8 11200 91West Campus Cogeneration Facility 7991_G_1 Combined Cycle WUMS 38.0 11985 83West Campus Cogeneration Facility 7991_G_CT2 Combined Cycle WUMS 37.2 11985 83West Campus Cogeneration Facility 7991_G_STG1 Combined Cycle WUMS 55.0 11985 83Ware Cogeneration 81542_G_1 Biomass NENG 4.1 15517 157Kimberly Clark 82800_G_CC1 Combined Cycle NENG 17.5 7031 79Kimberly Clark 82800_G_GT1 Combustion Turbine NENG 17.5 10664 124Great River Energy Spiritwood Station 82821_B_1 Coal Steam MRO 99.0 8763 89SPPN_KS_Coal steam 82932_C_1 Coal Steam SPPN 22.0 10820 89Cabot Holyoke 9864_B_5 O/G Steam 5.80 Not in dB 145Cabot Holyoke 9864_B_6 O/G Steam 5.80 Not in dB 145Cabot Holyoke 9864_B_7 O/G Steam 5.80 Not in dB 108Cabot Holyoke 9864_B_8 O/G Steam 5.80 Not in dB 145
35 

2 NOx Rates 

2.1 Response to the Comments Received 

Comment Theme: There were a substantial number of comments indicating that the NOx rates shown in 

NEEDS2

 were too low and not achievable. 

Discussion: Based on these comments, the decision rules used to derive the NEEDS NOx rates were 

reviewed and an out-of-date assumption was found to be causing instances of low NOx rates. Specifically, 

the out-of-date decision rule (which was developed at a time when units were subject, at most, to summer 

season, not annual, NOx rate limits) designated the winter NOx rate as the uncontrolled NOx rate. 

Applying percent reductions attributable to NOx post-combustion controls to the winter NOx rates resulted 

in unrealistically low controlled NOx rates for units that in reality operated NOx controls in the winter. 

Response: The previous decision rules were replaced by a more robust procedure for identifying 

uncontrolled NOx rates. In addition, a thorough review was made of all the decision rules affecting NOx

rates and, where appropriate, revisions were made. The revised decision rules are shown in the 

documentation supplement which follows. 

In addition, as announced in the Federal Register Notice of Data Availability for the Proposed Transport 

Rule (FR, vol. 75, no.169, September 1, 2010, 53614-53615) the NOx rates for fossil-fuel fired units in the 

final rule are based on 2009 data rather than 2007 NOx data used in the modeling for the proposed 

Transport Rule. Reported to EPA by generating units covered under Title IV of the Clean Air Act 

Amendments of 1990 (Acid Rain Program) and NOx Budget Program, the updated NOx rates more 

accurately reflect the unit level control installations that have occurred at power plants during the past 

several years. 

2.1 Resulting Updates 

The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model

show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case 

v4.10_FTransport.

In the documentation for EPA Base Case v.4.10_NODA, the following replaces the response to question 

Q4 that had previously appeared in Appendix 3-1 in the NODA documentation.

 

 

2 The National Electrical Energy Data System (NEEDS) is a database which provides EPA’s model of the 

electric power sector with information on all currently operating and planned-committed electric 

generating units. An updated version of NEEDS (v.4.10) was part of the September 1, 2010 Notice of 

Data Availability for the Proposed Transport Rule. 
36 

Q4: How are the values of the Mode 1-4 NOx rates derived? 

A4: The revised draft of the methodology to develop NOx rates for coal steam boilers in EPA Base Case 

v.4.10_FTransport is summarized below. 

The procedure employs the following hierarchy of NOx rate data sources: 

1. 2009 ETS 

2. EPA 410 NODA Comments 

3. 2007 ETS 

4. 2005 EIA Form 767 

5. Defaults 

The existing coal steam boilers in US are categorized into three groups depending on the configuration of 

NOx combustion and post-combustion controls 

Group 1 - Coal boilers without post combustion NOx controls

Mode 1 = 2009 ETS Annual Average NOx Rate 

Mode 2 = Mode 1 

Mode 3

For coal boilers located in a SIP call NOx, CAIR ozone/annual NOx or any NOx regulated state, 

Mode 3 = Mode 1 

For coal boilers that are not located in a SIP call NOx, CAIR ozone/annual NOx or any NOx regulated state, 

follow Steps 1-7 

Step 1: Pre-screen units that already have state of art (SOA) combustion controls from units that have nonSOA combustion controls from units that have no combustion controls 

Step 2: For units listed as not having combustion controls 

Make sure their NOx rates do not indicate that they really do have SOA control 

If Mode 1 > Cut-off (in Table 3-1.2), then Mode 1 = Base NOx rate. Go to Step 6 

If Mode 1 ≤ Cut-off (in Table 3-1.2), then the unit has SOA control and 

Mode 3 = Mode 1 

Step 3: For units listed as having SOA combustion controls. 

 Mode 3 = Mode 1. 

Step 4: For units listed as not having SOA combustion controls 

Make sure their NOx rates do not indicate that they really do have SOA control 

 

If Mode 1 ≤ Cut-off (in Table 3-1.2), then the unit has SOA control and 

Mode 3 = Mode 1 

If Mode 1 > Cut-off (in Table 3-1.2), then go to Step 5 

Step 5: Determine the unit’s Base NOx rate, i.e., the unit’s uncontrolled emission rate without combustion 

controls, using the appropriate equation (not in boldface italics) in Table 3-1.3 to back calculate their 

Base NOx rate. Use the default Base NOx rate values if back calculations can’t be performed. Once 

the Base NOx rate is obtained, go to Step 6. 

Step 6: Use the appropriate equations (in boldface italics) in Table 3-1.3 to calculate the NOx rate with SOA 

combustion controls. 

Step 7: Compare the value calculated in Step 6 to the applicable NOx floor rate in Table 3-1.2. 

If the value from Step 6 is ≥ floor, use the Step 6 value as Mode 3. Otherwise, use the floor as the 

Mode 3 NOx rate. 

Mode 4 

Mode 4 = Mode 3 

NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport 
37 

 

Group 2 - Coal boilers with Dispatchable/Non-Dispatchable SCR

Pre-screen coal boilers with 2009 ETS NOx rates into the following four operating regimes. A 

coal boiler is assumed to be operating its SCR when the seasonal NOx rate is less than 0.2 

lbs/MMBtu 

Group 2a. Coal boilers with Non-Dispatchable SCR

Group 2a.1 SCR is not operating in both summer and winter seasons

Follow the NOx rate rules summarized for Group 1 boilers. No state of the art 

combustion controls are implemented. 

Mode 1 = 2009 ETS Annual Average NOx Rate 

Mode 2 = maximum {(1-0.9) * Mode 1, 0.07} 

Mode 3 = Mode 1 

Mode 4 = Mode 2 

Group 2a.2 SCR is operating in summer only

Mode 1 = 2009 ETS Winter NOx Rate

Mode 2 = 2009 ETS Summer NOx Rate

Mode 3 = Mode 1 

Mode 4 = Mode 2 

Group 2a.3 SCR is operating in winter only

Mode 1 = 2009 ETS Summer NOx Rate

Mode 2 = 2009 ETS Winter NOx Rate

Mode 3 = Mode 1 

Mode 4 = Mode 2 

Group 2a.4 SCR is operating year-round

Mode 1 = if (2007 ETS Winter NOx Rate > 0.2, 2007 ETS Winter NOx Rate, 2009 ETS 

Annual Average NOx Rate) 

Mode 2 = 2009 ETS Annual Average NOx Rate 

Mode 3 = Mode 1 

Mode 4 = Mode 2 

Group 2b. Coal boilers with Dispatchable SCR

Group 2b.1 SCR is not operating in both summer and winter seasons

Follow the NOx rate rules summarized for Group2a.1 boilers. 

Group 2b.2 SCR is operating in summer only

Mode 1 = 2009 ETS Winter NOx Rate

Mode 2 = Mode 1

Mode 3 = Mode 1 

Mode 4 = Mode 2 

Group 2b.3 SCR is operating in winter only

Mode 1 = 2009 ETS Summer NOx Rate

Mode 2 = Mode 1

Mode 3 = Mode 1 

Mode 4 = Mode 2 

Group 2b.4 SCR is operating year-round

Mode 1 = if (2007 ETS Winter NOx Rate > 0.2, 2007 ETS Winter NOx Rate, 2009 ETS 

Annual Average NOx Rate) 

Mode 2 = Mode 1 

Mode 3 = Mode 1 

Mode 4 = Mode 2 

NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport (cont’d) 
38 

Group 3 - Coal boilers with SNCR

Step 1: Pre-screen coal boilers with 2009 ETS NOx rates to verify if they have not operated their 

SNCR in both summer and winter seasons. A coal boiler is assumed to be not operating its SNCR 

when the NOx rate is greater than 0.3 lbs/MMBtu in both summer and winter seasons. 

Group 3.1 SNCR is not operating in both summer and winter seasons

Follow the NOx rate rules summarized for Group 1 boilers 

Step 2: Pre-screen coal boilers with 2009 ETS NOx rates into the following three operating regimes. 

First estimate the implied removal for a coal boiler using the following equation: 

Implied Removal (%) = ((Winter NOx Rate – Summer NOx Rate)/ Winter NOx Rate) * 100 

Second, assign the coal boiler to a specific operating regime based on the following logic. 

If Implied Removal > 20% then SNCR is operating in summer season only, 

Else if Implied Removal < -20% then SNCR is operating in winter season only, 

Else SNCR is operating year-round 

Group 3.2 SNCR is operating in summer only

Mode 1 = 2009 ETS Winter NOx Rate 

Mode 2= 2009 ETS Summer NOx Rate

Mode 3 = same as Group 1 Mode 3 

 Mode 4 = maximum {(1-0.25) * Mode 3, 0.1} for non FBC units 

 Mode 4 = maximum {(1-0.50) * Mode 3, 0.08} for FBC units 

Note: The (1-.25) and (1-0.5) terms in the equations above represents the NOx removal 

efficiencies of SNCR for non FBC and FBC boilers. 

Group 3.3 SNCR is operating in winter only

Mode 1 = 2009 ETS Summer NOx Rate

Mode 2 = 2009 ETS Winter NOx Rate

Mode 3 = same as Group 3.2 Mode 3 

Mode 4 = same as Group 3.2 Mode 4 

Group 3.4 SNCR is operating year-round

Mode 1 = if (2007 ETS Winter NOx Rate > 0.3, 2007 ETS Winter NOx Rate, 2009 ETS Annual 

Average NOx Rate) 

Mode 2 = 2009 ETS Annual Average NOx Rate 

Mode 3 = same as Group 3.2 Mode 3 

Mode 4 = Mode 3 

NOx Rate Development Methodology for Coal Boilers in EPA Base Case v.4.10_FTransport (cont’d) 
39 

Table 3-1.1 Examples of Base and Policy NOx Rates Occurring in EPA Base Case v.4.10_FTransportPlant Name Unique ID 

PostCombusti

on 

Control 

Uncontroll

ed NOx

Base Rate 

Controll

ed NOx

Base 

Rate 

Uncontroll

ed NOx

Policy 

Rate 

Controll

ed NOx

Policy 

Rate 

Explana

Situation 1: For generating units that do not have post-combustion controls, the controlled and uncontrolled rat

Four 

Corners 2442_B_1 None 0.786 0.786 0.509 0.509 Situation 4 also applies, i.

now added OFA so see d

Situation 2: For generating units that do have post-combustion controls, the controlled and uncontrolled rates w

Big Sandy 1353_B_BS U2 SCR 0.629 0.146 0.629 0.146 (1) Has SCR so see differ

uncontrolled and controlle(2) Situation 3b also appli

Situation 3a: Base and Policy NOx rates will be same if the unit has state-of-the-art NOx combustion controls or . 

Greene 

County 10_B_2 None 0.363 0.363 0.363 0.363 Situation 1 also applies. 

Chalk Point 

LLC 

1571_B_1 SCR 

0.485 0.156 0.485 0.156 Situation 2 also applies. 

Situation 3b: . . . is in the NOx Regulated Region3 where current combustion controls are assumed to be retained

Thomas Hill 2168_B_MB 3 SCR 0.221 0.102 0.221 0.102 Situation 2 also applies. 

Waukegan 883_B_17 None 0.336 0.336 0.336 0.336 

(1) Has NOx combustion cdoesn't get added combu(2) Situation 1 also applie

Situation 4: Base and policy rates will differ if a unit does not currently have state-of-the-art combustion controls such controls in response to a NOx policy. 

Crist 641_B_4 SNCR 0.404 0.404 0.240 0.180

(1) Drop in uncontrolled pcompared to uncontrolled addition of combustion cofloor.) 

3NOx regulated region includes: Alabama, Arkansas, Connecticut, Delaware, District Of Columbia, Florida, Georgia, Illinois, Indiana

Maine, Maryland, Massachusetts, Michigan, Minnesota, Mississippi, Missouri, New Hampshire, New Jersey, New York, North Caro

Rhode Island, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin. 
40 

Table 3-1.2 Cutoff and Floor NOx Rates (lb/MMBtu) in EPA Base Case v.4.10_FTransport 

Boiler Type 

Cutoff Rate (lbs/MMBtu) Floor Rate (lbs/MMBtu) 

Bituminous Subbitumino

us 

Lignit

e 

Bituminous Subbitumino

us 

Lignit

e 

Wall-Fired 

Dry-Bottom 0.43 0.33 0.29 0.32 0.18 0.18 

Tangentially

-Fired 0.34 0.24 0.22 0.24 0.12 0.17 

CellBurners 0.43 0.43 0.43 0.32 0.32 0.32 

Cyclones 0.62 0.67 0.67 0.47 0.49 0.49 

VerticallyFired 0.57 0.44 0.44 0.49 0.25 0.25 

Table 3-1.3 NOx Removal Efficiencies for Different Combustion Control Configurations in EPA 

Base Case v.4.10_FTransport 

(State of the art configurations are shown in bold italic.) 

Boiler Type Coal Type Combustion Control 

Technology 

Fraction of 

Removal 

Default 

Removal 

Dry Bottom 

Wall-Fired Bituminous 

LNB 0.163 + 0.272* 

Base NOx 0.568 

LNB + OFA 0.313 + 0.272* 

Base NOx 

0.718 

Dry Bottom 

Wall-Fired 

Subbituminous

/Lignite 

LNB 0.135 + 0.541* 

Base NOx 0.574 

LNB + OFA 0.285 + 0.541* 

Base NOx 

0.724 

TangentiallyFired Bituminous 

LNC1 0.162 + 0.336* 

Base NOx 0.42 

LNC2 0.212 + 0.336* 

Base NOx 0.47 

LNC3 0.362 + 0.336* 

Base NOx 0.62 

TangentiallyFired Subbituminous

/Lignite 

LNC1 0.20 + 0.717* 

Base NOx 0.563 

LNC2 0.25 + 0.717* 

Base NOx 0.613 

LNC3 0.35 + 0.717* 

Base NOx 0.713 

Notes:

LNB = Low NOx Burner 

OFA = Overfire Air 

LNC = Low NOx Control 

 
41 

3 SO2 Removal Rates for Flue Gas Desulfurization (FGD) 

Comment Theme: In EPA Base Case v.4.10 the assumed SO2 removal efficiency for wet and dry FGD 

on new units and retrofits was 98% and 95% respectively. Comments indicated that the assumption of a 

98% SO2 removal rate for wet FGD on new units and retrofits might be suitable as a short-term 

performance guarantee but exceeded the long term removal rate that could be achieved under real 

operating conditions where load following is required. EPA was requested to use the same default wet 

and dry FGD removal rates as assumed in the previous base case v.3.0.2 EISA , i.e., 95% for wet FGD 

and 92% for dry FGD. 

Discussion: In response to this comment, it was decided to base removal rates for new and retrofit FGD 

on historical performance data reported in EIA 860 (2008) rather than on the engineering design 

capabilities of the controls, as was previously used in EPA Base Case v.4.10. This will put the removal 

rate assumptions for be new and retrofit FGD on the same basis as existing controls. 

Response: Default SO2 removal rates for wet and dry FGD were revised to be based on data reported in 

EIA 860 (2008). This ensures that they reflect operating removal rates rather than the engineering design 

removal rates which some commenters asserted could not be maintained under load following conditions. 

In particular, for new units and FGD retrofits installed by the model, the assumed SO2 removal rates will 

be 96% for wet FGD and 92% for dry FGD. These are the average of the SO2 removal efficiencies 

reported in EIA 860 (2008) for dry and wet FGD installed in 2008 or later. 

Existing units reporting FGD removal rates in form EIA 860 (2008) will be assigned those rates. However, 

to reduce the incidence of implausibly high, outlier removal rates, units whose reported EIA Form 860 

(2008) SO2 removal rates are higher than the average of the upper quartile SO2 removal rates will be 

assigned the upper quartile average unless the reported EIA 860 rate is confirmed in a submitted 

comment. One upper quartile removal rate is calculated across all installation years and replaces any 

reported removal rate that exceeds it no matter what installation year. Existing units not reporting FGD 

removal rates in form EIA 860 (2008) will be assigned the average of the applicable SO2 removal rate for 

a dry or wet FGD as reported in EIA 860 (2008) for the same FGD installation year. 

3.2 Resulting Updates 

The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model

show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case 

v4.10_FTransport.

In Chapter 3 − Power System Operation Assumptions 

Change the entries in Table 3-11 as shown in red on the following page. 
42 

Table 3-11 Emission and Removal Rate Assumptions for Potential (New) Units in EPA Base Case v.4.10_

Gas 

Controls, 

Removal, 

and 

Emissions 

Rates 

Supercritical 

Pulverized 

Coal - Wet 

Scrubber 

Supercritical 

Pulverized 

Coal - Dry 

Scrubber 

Integrated 

Gasification 

Combined 

Cycle 

Advanced 

Coal with 

Carbon 

Capture 

Advanced 

Combined 

Cycle 

Advanced 

Combustion 

Turbine 

Biomass 

Conventional 

Direct-Fired 

Boiler 

Biomass 

Gasification 

Combined 

Cycle 

SO2

Removal / 

Emissions 

Rate 

98% 96%with 

a floor of 0.06 

lbs/MMBtu 

93% 92% with 

a floor of 

0.065 0.08

lbs/MMBtu 

99% 99% None None 0.08 lbs/MMBtu 0.08 lbs/MMBtu 

NOx Emission Rate 0.07 lbs/MMBtu 0.05 lbs/MMBtu 0.013 lbs/MMBtu 0.013 lbs/MMBtu 0.011 lbs/MMBtu 0.011 lbs/MMBtu 0.36 lbs/MMBtu 0.102 lbs/MMBtu 

Hg 

Removal / 

Emissions 

Rate 

90% 90% 90% 90% 

Natural Gas:

0.000138 

lbs/MMBtu

Oil: 

0.483 

lbs/MMBtu 

Natural Gas: 

.000138 

lbs/MMBtu 

Oil: 

0.483 

lbs/MMBtu 

0.57 lbs/MMBtu 0.57 lbs/MMBtu 

CO2

Removal / 

Emissions 

Rate 

205.2 - 217.3 

lbs/MMBtu 

205.2 - 217.3 

lbs/MMBtu 

205.2 - 217.3 

lbs/MMBtu 90% 

Natural Gas:

117.08 

lbs/MMBtu

Oil: 

161.39 

lbs/MMBtu 

Natural Gas: 

117.08 

lbs/MMBtu 

Oil: 

161.39 

lbs/MMBtu 

None None 

HCl 

Removal / 

Emissions 

Rate 

99% 

0.0001 

lbs/mmBtu 

99% 

0.0001 

lbs/mmBtu 

99% 

0.0001 

lbs/mmBtu 

99% 

0.0001 

lbs/mmBtu 

− − − − 
43 

In Chapter 5 − Emission Control Technologies

Incorporate the changes shown in red below. 

5.1 Sulfur Dioxide Control Technologies 

Two commercially available Flue Gas Desulfurization (FGD) technology options for removing the SO2

produced by coal-fired power plants are offered in EPA Base Case v.4.10: Limestone Forced Oxidation 

(LSFO) — a wet FGD technology — and Lime Spray Dryer (LSD) — a semi-dry FGD technology which 

employs a spray dryer absorber (SDA). In wet FGD systems, the polluted gas stream is brought into contact 

with a liquid alkaline sorbent (typically limestone) by forcing it through a pool of the liquid slurry or by spraying 

it with the liquid. In dry FGD systems the polluted gas stream is brought into contact with the alkaline sorbent 

in a semi-dry state through use of a spray dryer. The removal efficiency for SDA drops steadily for coals 

whose SO2 content exceeds 3 lbs SO2/MMBtu, so this technology is provided only to plants which have the 

option to burn coals with sulfur content no greater than 3 lbs SO2/MMBtu. In EPA Base Case v.4.10 when a 

unit retrofits with an LSD SO2 scrubber, it loses the option of burning BG, BH, and LG coals due to their high 

sulfur content. 

In EPA Base Case v.4.10 the LSFO and LSD SO2 emission control technologies are available to existing 

"unscrubbed" units. They are also available to existing "scrubbed" units with reported removal efficiencies of 

less than fifty percent. Such units are considered to have an injection technology and classified as 

“unscrubbed” for modeling purposes in the NEEDS database of existing units which is used in setting up the 

EPA base case. The scrubber retrofit costs for these units are the same as regular unscrubbed units 

retrofitting with a scrubber. Scrubber efficiencies for existing units were derived from data reported in EIA 

Form 767 860 (2008). In transferring this data for use in EPA Base Case v.4.10 the following changes were 

made. The maximum removal efficiency was set at 98% for wet scrubbers and 93% for dry scrubber units. 

Existing units reporting efficiencies above these levels in Form 767 were assigned the maximum removal 

efficiency in NEEDS v.4.10 indicated in the previous sentence. Units whose reported EIA Form 860 (2008) 

SO2 removal rates were higher than the average of the upper quartile SO2 removal rates were assigned the 

upper quartile average unless the EIA 860 rate was confirmed in a comment submitted during the Transport 

Rulemaking . One upper quartile removal rate is calculated across all installation years and replaces any 

reported removal rate that exceeds it no matter what installation year. Existing units not reporting FGD 

removal rates in form EIA 860 (2008) were assigned the average of the applicable SO2 removal rate for a dry 

or wet FGD as reported in EIA 860 (2008) for the same FGD installation year.

As shown in Table 5-2, existing units that are selected to be retrofitted by the model with scrubbers are given 

the maximum removal efficiencies of 98% 96% for LSFO and 93% 92% for LSD. The procedures used to 

derive the cost of each scrubber type are discussed in detail in the following sections. 

Table 5-2 Summary of Retrofit SO2 Emission Control Performance Assumptions 

Performance 

Assumptions 

Limestone Forced 

Oxidation (LSFO) Lime Spray Dryer (LSD) 

Percent Removal 98% 96%

with a floor of 0.06 lbs/MMBtu 

93% 92% 

with a floor of 0.065 0.08

lbs/MMBtu 

Capacity Penalty Calculated based on 

characteristics of the unit: 

See Table 5-4 for examples 

Calculated based on 

characteristics of the unit: 

See Table 5-4 for examples 

Heat Rate Penalty 

Cost (2007$) 

Applicability Units ≥ 25 MW Units ≥ 25 MW 

Sulfur Content 

Applicability Coals ≤ 3 lbs SO2/MMBtu 

Applicable Coal Types BA, BB, BD, BE, BG, BH, SA, 

SB, SD, LD, LE, and LG 

BA, BB, BD, BE, SA, SB, SD, 

LD, and LE 

Potential (new) coal-fired units built by the model are also assumed to be constructed with a scrubber 

achieving a removal efficiency of 98% 96% for LSFO and 93% 92% for LSD. In EPA Base Case v.4.10 the 

costs of potential new coal units include the cost of scrubbers. 
44 

4 Coal Switching − Bituminous to Subbituminous 

4.1 Response to the Comments Received 

Comment Theme: In draft EPA Base Case v.410 it was assumed that generating units that had the 

option to burn both bituminous and subbituminous coal could use any proportion needed of each type of 

coal. Comments pointed out that there were limitations that prevented unrestricted switching at some 

existing generating units. 

Discussion: Based on these comments, a procedure was developed to capture limitations that prevent 

unrestricted switching from bituminous to subbituminous coal without incurring additional investment 

costs. The procedure consisted of the following steps: (1) Determining a level of subbituminous coal 

consumption indicative of an existing capability to burn 100% subbituminous coal. (2) Developing cost 

adders, heat rate penalties, and decision rules that would apply to units that don’t meet this threshold. 

In EPA Base Case v.4.10_FTransport, existing units with a historical record of burning a high percentage 

of subbituminous (specifically, 90% or more) are assumed to have made investments required for high 

percentage subbituminous firing. Existing units not meeting the 90% criteria incur a fuel cost adder and 

heat rate penalty for combusting more than a pre-specified percent of subbituminous. The cost adder is 

designed to reflect material handling and boiler modification costs. The heat rate penalty reflects the 

impact of the higher moisture content subbituminous coal on the unit’s heat rate. The procedure, which is 

summarized below, applies only to units that are currently designated to burn both bituminous and 

subbituminous coal in EPA Base Case v.4.10_FTransport. Historical fuel usage data is used to infer 

whether units have already made investments allowing them to burn unrestricted amounts of 

subbituminous coal. 

Staff engineering analyses indicated that (a) all boilers that are designated to burn both bituminous and 

subbituminous coal should be able to burn a limited percentage of subbituminous (i.e., below 20%) 

without incurring the cost of boiler modifications and fuel handling improvements and (b) while boiler 

improvements can remove the limitations on the amount of subbituminous coal burned at a unit, they 

come at a cost ($250/kW) and an associated heat rate penalty (5%). 

Consideration was given to allowing units that historically had burned more than 20%, but less than 90% 

subbituminous coal, to burn up to their historic maximum at no additional cost and only incur the 

additional cost and heat rate penalty when consuming above their historical maximum percent 

subbituminous use. However, comments (e.g., the 10/11/10 Dairyland Power Cooperative comment 

EPA-HQ-OAR-2009-0491-2733.1 on Genoa Unit 1) indicated that during the economic recession of 2007, 

2008, and 2009 when electricity demand was lower than normal, units burned higher proportions of 

subbituminous coal without making the investments that would otherwise have been necessary if their 

generation had been high enough to trigger a capacity derating. During the recession, units were not 

generating at high enough levels for capacity deratings to become an issue. Taking this into 

consideration, EPA took the more conservative approach of assuming that unless the unit historically had 

burned more than 90% subbituminous coal, it had not previously made the investments needed to burn 

more than 20% subbituminous coal. 

Response: The specifics of the procedure are as follows: 

(b) For coal plants that have the option to burn both bituminous and subbituminous coal in EPA Base 

Case v.4.10_FTransport, those that have burned 90% or more subbituminous coal in 2008, 2009, or 

first half of 2010 are assumed to have already made the fuel handling and boiler investments needed 

to burn up to 100% subbituminous coal and would therefore not face any additional costs. In 

addition, their reported heat rates are assumed to reflect the impact of burning the corresponding 

proportion of subbituminous coal. EIA Form 423 is used to determine the percent of subbituminous 

coal burned in 2008, 2009, and first half of 2010. 

(c) All other units with the option to burn both bituminous and subbituminous coal in EPA Base Case 

v.4.10, would have the option to burn 

(i) Less than 20% subbituminous coal without incurring any additional cost or heat rate penalty. 
45 

(j) Twenty percent (20%) or more subbituminous coal at a cost of $250/kW and a heat rate penalty 

of 5% to reflect additional fuel handling and boiler modification costs associated with burning 

higher proportions of subbituminous coal. The $250/kW cost adder is designed to cover boiler 

modifications or alternative power purchases in lieu of capacity deratings that would otherwise be 

associated with burning subbituminous coal with its lower heating value relative to bituminous 

coal. 

4.2 Resulting Updates 

The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model

show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case 

v4.10_FTransport.

Add the following paragraph between sections 9.3.9 and 9.4. 

 9.3.10 Coal Switching

Recognizing that boiler modifications and fuel handling enhancements may be required for 

unrestricted switching from bituminous to subbituminous coal, the following conditions apply in EPA 

Base Case v.4.10_FTransport to coal plants that have the option to burn both bituminous and 

subbituminous coal. 

Those that have burned 90% or more subbituminous coal in 2008, 2009, and first half of 2010 are 

assumed to have already made the fuel handling and boiler investments needed to burn up to 100% 

subbituminous coal and would therefore not face any additional costs. In addition, their reported heat 

rates are assumed to reflect the impact of burning the corresponding proportion of subbituminous 

coal. EIA Form 423 is used to determine the percent of subbituminous coal burned in 2008, 2009, 

and first half of 2010. 

All other units with the option to burn both bituminous and subbituminous coal in EPA Base Case 

v.4.10_FTransport, are subject to the following conditions: 

(1) If the unit consumes less than 20% subbituminous coal, no additional cost or heat rate penalty is 

incurred. 

(2) If the unit consumes twenty percent (20%) or more subbituminous coal, it incurs a cost of 

$250/kW and a heat rate penalty of 5% to reflect additional fuel handling and boiler modification 

costs associated with burning higher proportions of subbituminous coal. The $250/kW cost adder 

is designed to cover boiler modifications or alternative power purchases in lieu of capacity 

deratings that would otherwise be associated with burning subbituminous coal with its lower 

heating value relative to bituminous coal. The heat rate penalty reflects the impact of the higher 

moisture content subbituminous coal on the unit’s heat rate 
46 

5 Restrictions on coal choice in 2012 

Comment Theme: Some comments indicated that various factors (including coal contracts and boiler 

engineering considerations) limited the ability of coal units to change coal grades in the short to medium 

term and requested that the model reflect these limitations. 

Discussion: In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the 

unit’s engineering characteristics, the SO2 emissions limits they face, and the historical record of coals 

burned at the unit. Once the coal assignments are made, no further restrictions are typically placed on 

the fuels available to the unit. 

Factors limiting changes is near term coal use were considered technically plausible in the first model run 

year of 2012. Consequently, EPA incorporated such limitations in 2012 in cases where the affected units 

were explicitly identified, where sufficient documentation and an adequate explanation of the governing 

factors were provided, where EPA was not aware of data contradicting the claim, and where the inclusion 

of the limitation might affect modeling results. Beyond 2012, however, EPA’s assessment of industry 

experience suggested that economic considerations would take precedent over short-term restrictions 

and that the full choice of previously assigned coals should be re-instated for coal units. This would allow 

the model to make fuel choices based on economic factors reflecting the tendency of these factors to 

prevail beyond the short term. 

Response: 

(1) If a comment identified specific units that could not change from a specific coal due to short term 

constraints and generally met the conditions outlined above, the unit’s coal assignment in 2012 would 

be limited to the coal stipulated in the comment. If not explicitly stipulated in the comment, the coal 

reported most recently at the plant level in EIA Form 926 would be used. If the information was not 

reported in EIA Form 926, the unit would be assigned the coal grade which would result in an 

emission rate closest to the SO2 rate reported for the unit in EPA’s Emission Tracking System (ETS) 

2009. 

(2) If a comment identified by name a group of units (e.g., by company or by plant name) whose coal 

choices could not change over the short run, the same procedure as described in item #1 was 

followed, except that it was applied to all units in the group of units. 

(3) If a comment did not identify specific units or a specific set of units where coal choices were limited, 

no change was made. 

(4) After 2012, such restrictions no longer apply.. 

● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● ● 

Changes to be Incorporated in Documentation for EPA Base Case v.4.10 Using the Integrated 

Planning Model 

Add the following paragraph between new section 9.3.10 and before section 9.4. 

9.3.11 Short-term restrictions on coal choice

In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the unit’s 

engineering characteristics, the SO2 emissions limits they face, and the historical record of coals burned 

at the unit. Once the coal assignments are made, no further restrictions are typically placed on the fuels 

available to the unit. 

 

However, coal choice was further restricted in the first model run year (2012) in the modeling horizon in 

situations where information was provided to EPA indicating that short-term factors (like coal contracts 

and boiler engineering considerations) limited a unit’s choice to a particular assigned coal. Beyond the 

first model run year the full set of assigned coals was restored in keeping with the underlying modeling 

assumption that economic considerations prevail over short-term restrictions in the longer term.
47 

 9.3.11 Short-term restrictions on coal choice and related issues

In draft EPA Base Case v.4.10 generating units are given coal choices consistent with the unit’s 

engineering characteristics, the SO2 emissions limits they face, and the historical record of coals 

burned at the unit. Once the coal assignments are made, no further restrictions are typically placed 

on the fuels available to the unit. 

 

However, coal choice was further restricted in the first model run year (2012) in the modeling horizon 

in situations where information was provided to EPA indicating that short-term factors (like coal 

contracts and boiler engineering considerations) limited a unit’s choice to a particular assigned coal. 

Beyond the first model run year the full set of assigned coals was restored in keeping with the 

underlying modeling assumption that economic considerations prevail over short-term restrictions in 

the longer term.

In conjunction with these changes, limits were imposed in fuel assignments at four Texas coal steam 

plants to increase consistency with reported fuel use at the plants. The percentage of lignite used in 

the first model run year (2012) was calibrated so that it would not exceed the historical level reported 

in 2009, the latest year for available fuel data as reported in EIA Form 923. This limit was increased 

linearly in model run year 2015 so that by model run year 2020 there would no longer be a limit on 

lignite use. In other words by model run year 2020, the unit could choose to use up to 100% lignite if 

the model found that this was economically optimal. The four power plants that were affected by this 

procedure and the specific applicable limits are shown in the following table: 

Plant Name 

Plant 

ORIS 

ID 

Maximum Percent of Heat 

Input (MMBtu) from Lignite 

For IPM Run Years Shown 

2012 2015 2020 

Big Brown 3497 ≤ 50% ≤ 69% ≤ 100% 

Limestone 298 ≤ 54% ≤ 71% ≤ 100% 

Martin Lake 6146 ≤ 69% ≤ 80% ≤ 100% 

Monticello 6147 ≤ 19% ≤ 50% ≤ 100% 

In addition, post-modeling quality assurance checks flagged the 100% subbituminous coal 

consumption projected at the Martin Lake for 2012 as a discrepancy with the high share of lignite use 

(74% by weight, 69% on an MMBtu heat content basis) that was reported for 2009 at this lignite minemouth plant. To increase short-term modeling consistency with the plant’s recent operating history, its 

2012 SO2 emissions were re-calculated using its 2009 reported SO2 emission rate and its 2012 

projected heat input. 

Post-modeling quality assurance found a similar discrepancy between the short-term projection and 

operating history at Gibbons Creek (ORIS 6136) Unit 1 where reported SO2 emissions at the unit were 

indicative either of a unit not operating a scrubber or of a scrubber with a very low SO2 removal 

efficiency, i.e., producing emission roughly equivalent to the sulfur content of purchased coal as 

reported in the EIA-923, Since the unit’s scrubber had not been designated as “dispatchable” the 

model was forced to operate it, producing emissions in 2012 and 2014 that were not consistent with 

the recent operating experience of the unit. To increase short-term modeling consistency with the 

plant’s operating history, its 2012 and 2014 SO2 emissions were re-calculated to factor out the 

projected reductions from scrubbing. 
48 

6 Waste Coal Cost Correction 

6.1 Response to the Comments Received 

Comment Theme: Comments were received indicating that the cost of waste coal in draft EPA Base 

Case v.4.10 was much higher than actually encountered by buyers. 

Discussion: Upon investigation it was found that a data entry error had resulted in incorrect waste coal 

prices. The labeling of the prices in a file obtained by EPA from an outside source had indicated units of 

1987 dollars per short ton, which should have been labeled 2008 dollars per short ton. 

Response: The dollar year labeling error was corrected and costs were then properly converted to 2007 

dollars per short ton. The resulting corrected prices were consistent with those noted in the comment. 

6.2 Resulting Updates 

The following changes to Documentation for EPA Base Case v.4.10 Using the Integrated Planning Model

show the updates that were implemented for the Final Transport Rule analysis in EPA Base Case 

v4.10_FTransport. 

For waste coal entries only (Coal Supply Region: NA; Coal Grade: WC) replace the previous values 

shown under the “Cost of Production” with the corrected values (highlighted in yellow in the table below) 

Appendix 9-4 Coal Supply Curves in EPA Base Case V.4.10 

Waste Coal Entries Only 

Year 

Coal 

Supply 

Region 

Coal 

Grade 

Step 

Name 

Heat Content 

(MMBtu/Ton) 

Cost of Production 

(2007$/Ton) 

Coal 

Production 

(Million 

Tons/Year) Previous Corrected 

2012 NA WC S1 12.35 21.9 12.7 6.6 

2012 NA WC S2 12.35 22.8 13.3 3.9 

2012 NA WC S3 12.35 23.9 13.9 2.6 

2012 NA WC S4 12.35 24.3 14.2 0.9 

2012 NA WC S5 12.35 24.5 14.3 0.3 

2012 NA WC S6 12.35 24.6 14.3 0.1 

2012 NA WC S7 12.35 24.6 14.3 0.1 

2012 NA WC S8 12.35 24.8 14.4 0.3 

2012 NA WC S9 12.35 25.4 14.8 0.9 

2012 NA WC S10 12.35 28.8 16.7 2.6 

2012 NA WC S11 12.35 41.8 24.3 3.9 

2015 NA WC S1 12.35 22.0 12.8 7.2 

2015 NA WC S2 12.35 23.2 13.5 4.2 

2015 NA WC S3 12.35 24.6 14.3 2.8 

2015 NA WC S4 12.35 25.2 14.6 0.9 

2015 NA WC S5 12.35 25.4 14.8 0.3 

2015 NA WC S6 12.35 25.6 14.9 0.2 

2015 NA WC S7 12.35 25.7 15.0 0.2 

2015 NA WC S8 12.35 26.0 15.1 0.3 

2015 NA WC S9 12.35 27.1 15.8 0.9 

2015 NA WC S10 12.35 32.9 19.2 2.8 

2015 NA WC S11 12.35 58.7 34.2 4.2 
49 

 

Appendix 9-4 Coal Supply Curves in EPA Base Case V.4.10 

(cont’d) 

Waste Coal Entries Only

Year 

Coal 

Supply 

Region 

Coal 

Grade 

Step 

Name

Heat 

Content 

(MMBtu/Ton)

Cost of Production 

(2007$/Ton) 

Coal 

Production 

(Million 

Tons/Year) Previous Corrected 

2020 NA WC S1 12.35 22.1 12.9 6.8 

2020 NA WC S2 12.35 23.1 13.5 4.0 

2020 NA WC S3 12.35 24.3 14.2 2.7 

2020 NA WC S4 12.35 24.8 14.4 0.9 

2020 NA WC S5 12.35 25.0 14.5 0.3 

2020 NA WC S6 12.35 25.1 14.6 0.1 

2020 NA WC S7 12.35 25.2 14.7 0.1 

2020 NA WC S8 12.35 25.4 14.8 0.3 

2020 NA WC S9 12.35 26.1 15.2 0.9 

2020 NA WC S10 12.35 30.1 17.5 2.7 

2020 NA WC S11 12.35 46.1 26.9 4.0 

2030 NA WC S1 12.35 22.1 12.9 6.6 

2030 NA WC S2 12.35 23.0 13.4 3.9 

2030 NA WC S3 12.35 24.2 14.1 2.6 

2030 NA WC S4 12.35 24.6 14.3 0.9 

2030 NA WC S5 12.35 24.8 14.4 0.3 

2030 NA WC S6 12.35 24.9 14.5 0.1 

2030 NA WC S7 12.35 24.9 14.5 0.1 

2030 NA WC S8 12.35 25.1 14.6 0.3 

2030 NA WC S9 12.35 25.7 15.0 0.9 

2030 NA WC S10 12.35 29.1 16.9 2.6 

2030 NA WC S11 12.35 42.3 24.6 3.9 

2040 NA WC S1 12.35 22.2 12.9 6.8 

2040 NA WC S2 12.35 23.2 13.5 4.0 

2040 NA WC S3 12.35 24.4 14.2 2.6 

2040 NA WC S4 12.35 24.9 14.5 0.9 

2040 NA WC S5 12.35 25.1 14.6 0.3 

2040 NA WC S6 12.35 25.1 14.6 0.1 

2040 NA WC S7 12.35 25.2 14.7 0.1 

2040 NA WC S8 12.35 25.4 14.8 0.3 

2040 NA WC S9 12.35 26.2 15.2 0.9 

2040 NA WC S10 12.35 30.1 17.5 2.6 

2040 NA WC S11 12.35 45.8 26.7 4.0 
50 

 

Appendix 9-4 Coal Supply Curves in EPA Base Case V.4.10 

(cont’d) 

Waste Coal Entries Only 

Year 

Coal 

Supply 

Region 

Coal 

Grade 

Step 

Name

Heat 

Content 

(MMBtu/Ton)

Cost of Production 

(2007$/Ton) 

Coal 

Production 

(Million 

Tons/Year) Previous Corrected 

2050 NA WC S1 12.35 22.2 12.9 6.8 

2050 NA WC S2 12.35 23.2 13.5 4.0 

2050 NA WC S3 12.35 24.4 14.2 2.6 

2050 NA WC S4 12.35 24.9 14.5 0.9 

2050 NA WC S5 12.35 25.1 14.6 0.3 

2050 NA WC S6 12.35 25.1 14.6 0.1 

2050 NA WC S7 12.35 25.2 14.7 0.1 

2050 NA WC S8 12.35 25.4 14.8 0.3 

2050 NA WC S9 12.35 26.2 15.2 0.9 

2050 NA WC S10 12.35 30.1 17.5 2.6 

2050 NA WC S11 12.35 45.8 26.7 4.0 
51 

7 Comments Considered but that did not Result in Changes 

Oil consumption at dual fired (oil/gas) units 

Comment Theme: When compared with recent operating experience, the extent of oil burned by dual 

fuel generating units in draft EPA Base Case v.4.10 was considerably lower than some commenters 

thought it should be. 

Response: Consideration was given to a number of options for modifying the modeling of oil use at duel 

fuel units, but it was ultimately decided not to change the previous representation for the following 

reasons: 

(1) The underlying factors that could be causing greater oil consumption were very site specific and the 

information that would allow modeling such occurrences was not available. 

(2) In the absence of site specific information, imposing generic requirements for pre-specified levels of 

oil consumption was considered to have more drawbacks than the current representation. 

(3) Due to their small population, dual fired units are not likely figure significantly in modeling the 

Transport Rule. Enhanced modeling capability in this regard could be revisited if and when future 

policies are modeled where oil use by duel fuel units has significant policy implications.

Capital cost of Flue Gas Desulfurization (FGD) on units whose capacity is less than 100 MW

Comment Theme: Some commenters considered the capital cost assumptions in draft EPA Base Case 

v.4.10 for retrofitting generating units under 100 MW with FGD to be too low. For example, one 

commenter indicated that the v.4.10 FGD retrofit costs for these units should be multiplied by 4. 

Response: The original cost assumptions were retained. Specifically, the FGD capital cost for units 

below 100 MW is assumed to be the same as those for 100 MW units. While it is recognized that 

economies of scale would not be realized by units smaller than 100 MW that installed a standard FGD 

dedicated solely to that unit, prior engineering practice indicates a number of ways that costs will be held 

at the 100 MW level. Such practices include combining the emissions from multiple smaller units into a 

larger FGD and thereby achieving economy of scale. Another cost controlling approach for achieving 

economies of scale that has recently been seen in the marketplace is the development of innovative 

combinations of controls (e.g., dry sorbent injection, alkali injection, and circulating scrubbers) whose 

overall cost is lower than the sum of each of the constituent controls taken individually. These options 

provide a sound technical and economic basis for retaining the current approach of determining the 

capital cost of FGD for the universe of units less than 100 MW in EPA Base Case v.4.10 

Selective Catalytic Reduction (SCR) retrofit costs

Comment Theme: Assumed SCR retrofit costs are too low in EPA Base Case v.4.10 

Response: The SCR and FGD cost assumptions in EPA Base Case v.4.10 were updated in the summer 

of 2010 based on substantial engineering analyses and market assessments by an independent 

engineering firm. (This is documented on EPA web site at www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter5.pdf and www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Appendix52A.pdf.) In response to the comments received on SCR costs, EPA reviewed 

the cost assumptions and concluded not to modify them at this time. Although site specific conditions 

(which may the basis for the comments) can result in higher costs, the assumptions developed for EPA 

Base Case v.4.10 were deemed to be current, to have a strong economic and engineering basis, and to 

be applicable across the fleet of U.S. generating units. 

30 year book life for emission control retrofits

Comment Theme: The 30 year book life assumed for retrofits in v.4.10 is too long. Many retrofits are on 

smaller and older units where an additional 20-30 year of life is not likely. 

Response: For several reasons, the 30 year book life assumption for emission control retrofits was 

retained. First, as described in section 4.2.8 and Table 4-10 of Documentation for EPA Base Case v.4.10 

Using the Integrated Planning Model (www.epa.gov/airmarkets/progsregs/epa-
52 

ipm/docs/v410/Chapter4.pdf), existing units in EPA Base Case v.4.10 incur a life extension cost if they 

remain in operation past their current expected lifespan. (For existing coal units this occurs when they 

pass age 40.) The assumption of a 30-year book life for retrofits is consistent with these life extension 

provisions which allow existing units to stay in operation throughout the 2012-2050 modeling time 

horizon, rather than forcing them retire upon reaching a pre-specified expected lifespan. The 30-year 

book life is in line with the 30-year design life typically specified in purchase agreements to ensure the 

quality of materials and cyclic fatigue life of power boilers, turbines and associated emission control 

systems. It is also well within the service life of such equipment which extends far beyond 30 years when 

generally accepted maintenance practices are followed.

Must run, black start, and spinning reserve units

Comment Theme: The model retires units that some commenters identified as being prevented from 

retiring for reliability purposes 

Response: There are several reasons for retaining the current approach that does not attempt to account 

for “must run” units and does not prevent such units from retiring. First, for competitive business reasons, 

a comprehensive listing of must-run units is not available from either public or private sources. Limiting 

the “must run” designation only to those units identified in comments would introduce inconsistency 

across the universe of units. Second, there is no technically sound approach for defining the extent of 

operation of a “must run” unit. Finally, there is no technical basis for defining the period over which the 

“must run” designation would last. This is a particularly important issue in view of the long modeling time 

horizon (2012 to 2050) in EPA Base Case v.4.10. 

Availability assumptions for existing coal units 

Comment Theme: The availability assumption for coal units in EPA Base Case v.4.10 should not be 

based on historical capacity factor data from the Energy Information Administration’s Annual Energy 

Outlook 2010 (AEO 2010 but on availabilities in NERC GADS as was done in previous EPA base cases 

(including v.3.0.2 EISA) 

Response: Rather than using NERC GADS availabilities, EPA Base Case v.4.10 adopts an approach 

similar to AEO 2010 of using historical capacity factors to define the availabilities of existing coal units. 

The change was a result of analysis that showed that for a large portion of the coal fleet, actual capacity 

factors for existing coal units fell below the availabilities in NERC GADS. It is also based on an 

assessment that indicated that the system-level availabilities that are found in NERC GADS were not 

entirely comparable to the plant level availabilities required for IPM. Comparing previous base case 

projections to historical data showed tendencies to over-project coal consumption and under-project gas 

consumption as a result of the use of the GADS availabilities. Consequently, v.4.10 adopts the approach 

used in AEO 2010 and other modeling efforts which tie availability assumptions for existing coal units to 

historical capacity factors (plus a growth assumption for capacity factors below 75% and an upper cut off 

of 95% to reflect an assumed 5% force outage rate). The historical capacity factors used to derive the 

availability assumptions in EPA Base Case v.4.10 were obtained from AEO 2010. 

 
53 

Addenda − Notes on various modeling assumptions 

Though not necessarily responses to comments received on the Transport Rule or NODA, the following 

features of EPA Base Case v.4.10_FTransport are annotated below for purposes of documentation. 

1. Dry Sorbent Injection (DSI) and Fabric Filter Cost Development Section 5.5.3.2 and Appendix 5-

4 on dry sorbent injection and section 5.5.4 and Appendix 5-5 on fabric filter cost development are 

incorporated below from the Documentation Supplement for EPA Base Case v.4.10_Ptox – Updates 

for Proposed Toxics Rule. Minor changes have been made to the text to highlight aspects particularly 

relevant to the Final Transport Rule, i.e., the use of DSI in combination a fabric filter as a retrofit 

option for SO2 control. 

2. Variable Operating and Maintenance (VOM) Cost of Dry Sorbent Injection (DSI) Retrofits: In 

modeling the Final Transport Rule (i.e., in EPA Base Case v.4.10_FTransport), DSI is provided as a 

retrofit for units burning coals with an SO2 content of less than 2 lbs/mmBtu and is assumed to be 

retrofit in conjunction with a fabric filter. When retrofit on units with a pre-existing fabric filter, it is 

assumed that no ESP is present and that the DSI is installed upstream of the FF. Consequently, the 

fly ash that is caught in the fabric filter will be contaminated by the sorbent and not marketable. Since 

the entire combined fly ash, reaction products, and unreacted sorbent mass will have to be disposed, 

the full DSI capital, FOM, and VOM costs are incurred. In contrast, when DSI is retrofit on units with 

no pre-existing fabric filter, it is assumed that the DSI will be installed after the ESP (which, in the 

absence of a FF, will be present for PM control) and upstream of the FF which is installed in 

conjunction with the DSI. Since the upstream ESP will capture the fly ash before it arrives at the DSI, 

it will not be contaminated by the sorbent and can be sold rather than disposed. (Note: No credit for 

fly ash sales is taken into account in IPM.) Only the reaction products and unreacted sorbent which is 

caught in the FF will need to be landfilled. Since the waste disposal cost only applies to the sorbent, 

there is a 35% reduction in VOM. In this situation the reduced VOM and standard capital and FOM 

costs are incurred for the DSI retrofit plus the capital, FOM, and VOM costs for the associated FF.

3. Updated Appendices 3-2 through 3-4: These appendices, which are included below, show the 

state power sector air emissions regulations (Appendix 3-2), NSR settlements (Appendix 3-3) and 

state settlements (Appendix 3-4) that are represented in EPA Base Case v.4.10_FTransport.

4. 2012 Emission Control Retrofits: In EPA’s modeling for the Final Transport Rule, emission controls 

in response to the Transport Rule are not allowed to be occur in 2012, the first model run year, 

because of insufficient lead time to install flue gas desulfurization (FGD) for SO2 and selective 

catalytic reduction (SCR) for NOx control by 2012. However, in order not to overstate the emission 

levels without the Transport Rule, emission controls are allowed to occur in 2012 in response to nonTransport Rule legal requirements that were in place in 2010 or earlier. While the specific controls 

that the model builds and operates (or partially operates) may not correspond to those actually 

installed as part of a source’s compliance strategy, they should capture valid levels of emission 

reductions that can be expected to be achieved in complying with binding non-Transport Rule 

agreements or regulations. This dual approach to 2012 retrofits is implemented by allowing the 

model to install emission control retrofits in 2012 in the base case (which does not include Transport 

Rule but does include binding non-Transport Rule legal requirements). Any 2012 retrofits occurring in 

the base case are then carried over into the “Remedy” policy case (which includes the Final Transport 

Rule emission requirements), but the model is not allowed to install any additional 2012 emission 

controls (which would come in response to the Transport Rule requirements). 

5. Emission Controls in IPM Parsed Files: Users are sometimes unclear about the origins of the 

advanced post-combustion emission controls (e.g., FGD or SCR) that appear in the “parsed files” for 
54 

an IPM model run. These controls originate in one of four possible sources. (1) Most existing controls 

are the same as those found in the National Electric Energy Data System (NEEDS), the database of 

existing and planned/committed units which serves as the starting point for setting up EPA’s base and 

policy cases using IPM. For the Final Transport Rule existing controls are those present in 2011 or 

earlier. (2) A small number of existing emission controls appear in parsed files, but are not found in 

NEEDS. They are controls that became known after the NEEDS database was “frozen” for purposes 

of setting up a family of model runs. Rather than appearing in NEEDS, they are represented directly 

in IPM as emission control retrofit options available from the start of the modeling time horizon. They 

can either be forced to operate through the imposition of modeling constraints (in which case they are 

termed “non-dispatchable” controls) or be left for the model to determine endogenously whether 

emission policies require them to operate (in which case they are termed “dispatchable” controls). (3) 

Some generating units have either (a) an existing legal requirement, such as a consent decree or 

state rule requiring the installation of a control by a particular date post 2011, or (b) have publically 

announced or submitted comment noting the installation and/or beginning of construction of a control 

for post 2011 start-up. In instances where the control is expected in the future, but not present by 

2011 or earlier, the control is represented directly in IPM as a retrofit option which is either forced by a 

modeling constraint to be installed and operate (non-dispatchable controls) or left for the model to 

determine whether they need to operate (dispatchable controls). These controls appear in the model 

run year corresponding to the year they are expected to operate (typically 2012 or 2015) both in IPM 

outputs and parsed files. They do not appear in NEEDS (since they were not present prior to 2012). 

(4) The remaining emission controls found in parsed files are those that the model builds as part of 

the optimal (most cost effective) solution in response to all the requirements faced by the electric 

power system represented in the model. 

6. Mercury Emission Modification Factor (EMF) for Waste Coal Units: In EPA Base Case 

v.4.10_FTransport (as in the base case for the proposed Mercury and Air Toxics Standards Rule - 

EPA Base Case v.4.10_PTox), all waste coal units are assumed to have a mercury EMF of 0.02.

7. Carbon dioxide (CO2) Emissions from Chemical Reactions in a Wet Flue Gas Desulfurization 

(FGD) System for Sulfur Dioxide (SO2) Control: In EPA applications of IPM the chemical reactions 

in a limestone forced oxidation (LSFO) system (also known as a wet FGD or wet scrubber) are 

assumed to cause CO2 increases according to the following equation:

 CO2 increase in % of total CO2 from fuel = 

 0.35 X SO2 emission rate of the fuel (in lb/MMBtu) – 0.02 

For example, for coal with an SO2 emission factor of 4.3 lb/MMBtu, the increase in CO2 is 1.485%. In 

contrast to LSFO, there is no representation of direct emissions of CO2 or other greenhouse gases 

from the other control technologies in IPM. These include limestone spray dryers (LSD) for SO2

control, dry sorbent injection (DSI) for SO2 and hydrogen chloride (HCl) control, selective catalytic 

reduction (SCR) and selective non-catalytic reduction (SNCR) for NOx control, and activated carbon 

injection (ACI) for mercury control. 

 
55 

Addendum A ─ Dry Sorbent Injection (DSI) and Fabric Filter 

Cost Development in EPA Base Case v.4.10_FTransport 

Note: The numbering of the sections and tables in this addendum is the same as found in the 

Documentation Supplement for EPA Base Case v.4.10_Ptox – Updates for Proposed Toxics Rule, where 

this material originally appeared. 
56 

Table 5-21 Summary of Retrofit SO2 (and HCl) Emission Control Performance Assumptions in v4.10_FTr

Performance 

Assumptions 

Limestone Forced Oxidation 

(LSFO) Lime Spray Dryer (LSD) Dry Sorbent In

SO2 HCl SO2 HCl SO2 

Percent Removal 

96% 

with a floor of 

0.06 lbs/MMBtu 

99% 

with a floor of 

0.0001 

lbs/MMBtu 

92% 

with a floor of 

0.065 lbs/MMBtu 

99% 

with a floor of 

0.0001 

lbs/MMBtu 

With fabric 

filter: 70% 

−−−

With an 

electrostatic 

percipitator2:

50% 

Capacity Penalty -1.65% -0.70% -0.6Heat Rate Penalty 1.68% 0.71% 0.6Cost (2007$) See Table 5-3 and 5-4 See Table 5-3 and 5-4 See TableApplicability Units ≥ 25 MW Units ≥ 25 MW Units ≥ Sulfur Content Applicability Coals ≤ 2.0% Sulfur by Weight Coals ≤ 2.0 lb/Applicable Coal Types 

BA, BB, BD, BE, BG, BH, SA, SB, 

SD, LD, LE, and LG 

BA, BB, BD, BE, SA, SB, SD, LD, 

LE, and LG BA, BB, BD, SA, 

Notes1. The cost and performance values shown in this table apply to existing units with pre-existing fabric filters or electrostatUnits with neither ESP nor FF are assumed to have to install a fabric filter in order to qualify for the DSI retrofit. 2. The option to retrofit DSI on existing units with ESP was not offered in the runs performed for the current rulemaking. 
57 

5.5.3.2 Dry Sorbent Injection 

EPA Base Case v4.10_FTransport includes dry sorbent injection (DSI) as a retrofit option for achieving (in 

combination with a particulate control device) SO2 (and HCl) removal. With DSI a dry sorbent is injected 

into the flue gas duct where it reacts with the SO2 and HCl in the flue gas to form a compound, which is 

then captured in a downstream fabric filter or electrostatic precipitator (ESP) and disposed of as waste. 

(A sorbent is a material that takes up another substance by either adsorption on its surface or absorption 

internally or in solution. A sorbent may also chemically react with another substance.) The sorbent 

assumed in the cost and performance characterization discussed in this section is trona, a sodium-rich 

material with major underground deposits found in Sweetwater County, Wyoming. Trona is typically 

delivered with an average particle size of 30 μm diameter, but can be reduced to about 15 μm through 

onsite in-line milling to increase its surface area and capture capability. 

 

Removal rate assumptions: The removal rate assumptions for DSI are summarized in Table 5-21. The 

assumptions shown in the last two columns of Table 5-21 were derived from assessments by EPA 

engineering staff in consultation with Sargent & Lundy. As indicated in this table, the assumed SO2 

removal rate for DSI + ESP is 50% and for DSI + fabric filter is 70%. The assumed HCl removal rate is 

60% for DSI + ESP and 90% for DSI + fabric filter. (This is noted in the next-to-the-last column in Table 

5-21.) Although the option to retrofit DSI on existing units with ESP is shown in Table 5-21 it was not 

offered in the runs performed for the current rulemaking. 

Methodology for Obtaining DSI Control Costs: The engineering firm of Sargent & Lundy, whose analyses 

were used to update the cost of SO2 and post-combustion NOx controls in EPA Base Case , v4.10, 

performed similar engineering assessments of the cost of DSI retrofits with two alternative, associated 

particulate control devices, i.e., ESP and fabric filter (also called a “baghouse”). Their analysis of DSI 

noted that the cost drivers of DSI are quite different from those of wet or dry FGD. Whereas plant size 

and coal sulfur rates are key underlying determinants of FGD cost, sorbent feed rate and fly ash waste 

handling are the main drivers of the capital cost of DSI with plant size and coal sulfur rates playing a 

secondary role. 

 

Sorbent feed rate determines the amount of sorbent required and the size and extensiveness of the DSI 

installation. The sorbent feed rate needed to achieve a specified percent SO2 or HCl removal4

 is firstly a 

function of the flue gas SO2 rate (which, in turn, is a function of the sulfur content of the coal burned, 

expressed in lbs of SO2/mmBtu ), the unit’s size and heat rate, and the sorbent particle size (which 

determines whether in-line milling is needed). The sorbent feed rate is also a function of the residence 

time of the sorbent in the flue gas stream and the extent of mixing and penetration of the sorbent in the 

flue gas. Residence time, penetration, and mixing are largely dependent on the type of particulate 

control device use (electrostatic precipitator or fabric filter). 

In EPA Base Case v4.10_FTransport the DSI sorbent feed rate and variable O&M costs are based on 

assumptions that a fabric filter and in-line trona milling are used, and that the SO2 removal rate is 60%. 

The corresponding HCl removal effect is assumed to be 90%, based on information from Solvay 

Chemicals (H. Davidson, Dry Sorbent Injection for Multi-pollutant Control Case Study, CIBO IECT VIII, 

August 2010). 

The cost of fly ash waste handling, the other key contributor to DSI cost, is a function of the type of 

particulate capture device and the flue gas SO2 rate (which, as noted above, is itself a function of the 

 

4

For purposes of engineering calculations the percent removal is often translated into a corresponding

“Normalized Stoichiometric Ratio” (NSR) associated with a particular percent removal, where the NSR is defined as

ܴܰܵ ൌ ቀ ௠௢௟௘௦ ௢௙ ௦௢௕௘௡௧ ௜௡௝௘௖௧

௠௢௟௘௦ ௢௙ ௌைଶ ௜௡ ௙௟௨௘ ௚௔௦ቁ

൘ ሻ݁݀ݎ݅ݑݍ݁ݎ ݐܾ݁݊ݎ݋ݏ ݂݋ ݏ݈݁݋݉ ݈݅ܿܽݐ݁ݎ݋݄݁ݐሺ
58 

sulfur content of the coal and the unit’s size and heat rate). Fly ash waste handling costs are also a 

function of the ash content and the higher heating value (HHV) of the coal. The governing variables of 

the key capital cost components of DSI are presented in Table 5-22. 

Table 5-22. Capital Cost Components and Their Governing Variables for HCl Removal with 

DSI. 

Module 

Retrofit 

Difficulty 

(1 = 

average) 

Particulate 

Capture 

Type 

(ESP or 

Baghouse) 

Sorbent 

Particle 

Size 

Requirement 

(milled or 

unmilled) 

Heat 

Rate

(Btu/

kWh) 

SO2 

Rate 

of coal

(lb/ 

MMBtu) 

Ash 

Content 

of Coal 

(percent) 

Higher 

Heating 

Value 

(HHV) 

of Coal 

(Btu/lb) 

Unit 

Size 

(MW) 

Sorbent 

Feed 

Handling 

X X X X X 

Fly Ash 

Waste 

Handling 

X X X X X X 

Once the key variables for the two DSI modules are identified, they are used to derive costs for each 

base module component. These costs are then summed to obtain total bare module costs. The base 

installed cost for DSI includes 

• All equipment 

• Installation 

• Buildings 

• Foundations 

• Electrical 

• Average retrofit difficulty 

• In-line milling equipment is assumed to be included 

This total is increased by 15% to account for additional engineering and construction management costs, 

labor premiums, and contractor profits and fees. The resulting value is the capital, engineering, and 

construction cost (CECC) subtotal. To obtain the total project cost (TPC), the CECC subtotal is increased 

by 5% to account for owner’s home office costs, i.e., owner’s engineering, management, and 

procurement costs. Since DSI installations are expected to be completed in less than a year, no 

Allowance for Funds used During Construction (AFUDC) is provided for DSI. The cost resulting from 

these calculations is the capital cost factor (expressed in $/kW) that is used in EPA Base Case 

v4.10_FTransport. 

Variable Operating and Maintenance Costs (VOM): These are the costs incurred in running an emission 

control device. They are proportional to the electrical energy produced and are expressed in units of $ per 

MWh. For DSI, Sargent & Lundy identified three components of VOM: (a) costs for sorbent usage, (b) 

costs associated with waste production and disposal, (c) cost of additional power required to run the DSI 

control (often called the “parasitic load”). For DSI, sorbent usage is a function of the “Normalized 

Stoichiometric Ratio” and SO2 feed rate. As noted above the feed rate is a function of the SO2 rate of the 

coal and the unit’s size and heat rate. 

Total waste production involves the production of both reacted and unreacted sorbent and fly ash. 
59 

Sorbent waste is a function of the sorbent feed rate with an adjustment for excess sorbent feed. Use of 

DSI makes the fly ash unsalable, which means that any fly ash produced must be landfilled along with the 

reacted and unreacted sorbent waste. Typical ash contents for each fuel are used to calculate a total fly 

ash production rate. The fly ash production is added to the sorbent waste to account for the total waste 

stream for the VOM analysis. 

For purposes of modeling, the total VOM includes the first two component costs noted in the previous 

paragraph, i.e., the costs for sorbent usage and the costs associated with waste production and disposal,. 

The last component – cost of additional power – is factored into IPM, not in the VOM value, but through a 

capacity and heat rate penalty as described in the next paragraph. 

Capacity and Heat Rate Penalty: The amount of electrical power required to operate the DSI is 

represented through a reduction in the amount of electricity that is available for sale to the grid. For 

example, if 0.65% of the unit’s electrical generation is needed to operate DSI, the generating unit’s 

capacity is reduced by 0.65%. This is the “capacity penalty.” At the same time, to capture the total fuel 

used in generation both for sale to the grid and for internal load (i.e., for operating the DSI device), the 

unit’s heat rate is scaled up such that a comparable reduction (0.65% in the previous example) in the new 

higher heat rate yields the original heat rate. The factor used to scale up the original heat rate is called 

“heat rate penalty.” It is a modeling procedure only and does not represent an increase in the unit’s actual 

heat rate (i.e., a decrease in the unit’s generation efficiency). As was the case for FGD in EPA Base 

Case v4.10, specific DSI heat rate and capacity penalties are calculated for each installation. For DSI the 

installation specific calculations take into account the additional power required by air blowers for the 

injection system, drying equipment for the transport air, and in-line milling equipment, if required. 

Fixed Operating and Maintenance Costs (FOM): These are the annual costs of maintaining an emission 

control. They represent expenses incurred regardless of the extent to which the emission control system 

is run. They are expressed in units of $ per kW per year. In calculating FOM Sargent & Lundy took into 

account labor and materials costs associated with operations, maintenance, and administrative functions. 

The following assumptions were made: 

• FOM for operations is based on the number of operators needed which is a function of the size 

(i.e., MW capacity) of the generating unit. In general for DSI two (2) additional operators are 

assumed to be needed. 

• FOM for maintenance is a direct function of the DSI capital cost. 

• FOM for administration is a function of the FOM for operations and maintenance. 

Table 5-23 presents the capital, VOM, and FOM costs as well as the capacity and heat rate penalties of a 

DSI retrofit for an illustrative and representative set of generating units with the capacities and heat rates 

indicated. 

Illustration worksheets of the detailed calculations performed to obtain the capital, VOM, and FOM costs 

for an example DSI appear in Appendix 5-4. The worksheets were developed by Sargent & Lundy5

.

 

5

These worksheets were extracted from Sargent & Lundy LLC, IPM Model – Revisions to Cost and 

Performance for APC Technologies: Complete Dry Sorbent Injection Cost Development Methodology 

(Project 12301-007), May 2010. The complete report is available for review and downloading at 

www.epa.gov/airmarkets/progsregs/epa-ipm/. 
60 

Table 5-23. Illustrative Dry Sorbent Injection (DSI) Costs for Representative Sizes and Heat Rates Under Assumpt

v4.10_FTransport 

Control 

Type 

Heat Rate 

(Btu/ 

kWh) 

SO2 

Rate 

(lb/ 

MMBtu) 

Capacity 

Penalty 

(%) 

Heat Rate 

Penalty 

(%) 

Variable 

O&M 

(mills/ 

kWh) 

Capacity (MW) 

100 300 500 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Cap

Co

($/k

DSI - FF 9,000 2.0 0.64 0.65 6.05 122 2.25 55 0.87 38 0.57 30 Assuming Bituminous Coal 

10,000 2.0 0.71 0.72 6.72 125 2.28 57 0.89 40 0.58 31 11,000 2.0 0.79 0.79 7.40 129 2.30 59 0.90 41 0.59 34 

DSI - ESP 9,000 2.0 1.08 1.10 11.23 141 2.41 64 0.94 47 0.64 47 Assuming Bituminous Coal 

10,000 2.0 1.20 1.22 12.47 145 2.44 66 0.96 52 0.68 52 11,000 2.0 1.32 1.34 13.72 149 2.48 68 0.98 58 0.73 58 
61 

 

5.5.4 Fabric Filter (Baghouse) Cost Development 

Fabric filters are not endogenously modeled as a separate retrofit option in EPA Base Case 

v4.10_FTransport, but are accounted for as a cost adder when installed in conjunction with DSl. In EPA 

Base Case v4.10_FTransport, an existing or new fabric filter particulate control device is a pre-condition 

for installing a DSI retrofit. Any unit that is retrofit by the model with DSI and does not have an existing 

fabric filter incurs the cost of installing a fabric filter. This cost is added to the DSI costs discussed in 

section 5.5.3.2. This section describes the methodology used by Sargent & Lundy to derive the cost of a 

fabric filter. 

The engineering cost analysis is based on a pulse-jet fabric filter which collects particulate matter on a 

fabric bag and uses air pulses to dislodge the particulate from the bag surface and collect it in hoppers for 

removal via an ash handling system to a silo. This is a mature technology that has been operating 

commercially for more than 25 years. “Baghouse” and “fabric filters” are used interchangeably to refer to 

such installations. 

Capital Cost: Two governing variables are used to derive the bare module capital cost of a fabric filter. 

The first of these is the “air-to-cloth” (A/C) ratio. The major driver of fabric filter capital cost, the A/C ratio 

is defined as the volumetric flow, (typically expressed in Actual Cubic Feet per Minute, ACFM) of flue gas 

entering the baghouse divided by the areas (typically in square feet) of fabric filter cloth in the baghouse. 

The lower the A/C ratio, e.g., A/C = 4.0 compared to A/C = 6.0, the greater the area of the cloth required 

and the higher the cost for a given volumetric flow. 

The other determinant of capital cost is the flue gas volumetric flow rate (in ACFM) which is a function of 

the type of coal burned and the unit’s size and heat rate. 

The capital cost for fabric filters include: 

• Duct work modifications, 

• Foundations, 

• Structural steel, 

• Induced draft (ID) fan modifications or new booster fans, and 

• Electrical modifications. 

After the bare installed total capital cost is calculated, it is increased by 20% to account for additional 

engineering and construction management costs, labor premiums, and contractor profits and fees. The 

resulting value is the capital, engineering, and construction cost (CECC) subtotal. To obtain the total 

project cost (TPC), the CECC subtotal is increased by 5% to account for owner’s home office costs, i.e., 

owner’s engineering, management, and procurement costs, and by another 6% to account for Allowance 

for Funds used During Construction (AFUDC) which is premised on a 2-year project duration. 

The cost resulting from these calculations is the capital cost factor (expressed in $/kW). Fabric filter 

capital costs are implemented in EPA Base Case v4.10_FTransport as an FOM adder. Plants that install 

fabric filters incur a total FOM charge which includes the true FOM associated with the fabric filter plus a 

capital cost FOM Adder derived by multiplying the capital cost by a capital charge rate of 11.3%, i.e., 

Total FOM = True FOM + Capital Cost FOM Adder 

where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3% 

In EPA Base Case v4.10_FTransport the capital cost of a fabric filter is based on the use of a “polishing” 

fabric filter designed with A/C=6.0. This basis results in a capital cost that is at least 10% less than the 

cost of a design with A/C=4.0, and assumes that the existing ESP remains in place and active. 
62 

Variable Operating and Maintenance Costs (VOM): For fabric filters the VOM is strictly a function of the 

costs of the fabric filter bag and cage translated in a $/MWhr cost based on the filter and bag replacement 

cycle for a specified A/C ratio. For units whose A/C ratio = 6.0, the replacement cycle for the bag is 3 

years and the cage is 9 years, whereas for units whose A/C ratio = 4.0, the bag and cage replacement 

cycles are 5 and 10 years respectively. 

Capacity and Heat Rate Penalty: Conceptually, the capacity and heat rate penalties for fabric filters 

represent the amount of electrical power required to operate the baghouse and are calculated by the 

same procedure used when calculating the capacity and heat rate penalty for DSI as described in section 

5.5.3.2. The resulting capacity and heat rate penalties are both 0.6%. 

However, since fabric filters were not endogenously modeled as a retrofit option, but simply added to the 

DSI costs for generating units that do not have an existing baghouse, the capacity and heat rate penalties 

described here were not factored into the representation of fabric filters in EPA Base Case 

v4.10_FTransport. 

Fixed Operating and Maintenance Costs (FOM): Sargent & Lundy’s engineering analysis indicated that 

no additional operations staff would be required for a baghouse. Consequently the FOM strictly includes 

two components: 

• FOM for maintenance is a direct function of the DSI capital cost. 

• FOM for administration is a function of the FOM for operations (which is zero) and maintenance. 

Table 5-24 presents the capital, VOM, and FOM costs for fabric filters as represented in EPA Base Case 

v4.10_FTransport for an illustrative set of generating units with a representative range of capacities and 

heat rates. 

Worksheets illustrating the detailed calculations performed to obtain the capital, VOM, and FOM costs for 

two example fabric filters (A/C Ratio = 4.0 and A/C Ratio = 6.0) appear in Appendix 5-5. The worksheets 

were developed by Sargent & Lundy6

. 

 

6 These worksheets were extracted from Sargent & Lundy LLC, IPM Model – Revisions to Cost and 

Performance for APC Technologies: Particulate Control Cost Development Methodology (Project 12301-

009), October 2010. The complete report is available for review and downloading at 

www.epa.gov/airmarkets/progsregs/epa-ipm/. 
63 

Table 5-24. Illustrative Fabric Filter (Baghouse) Costs for Representative Sizes and Heat Rates Under Assumptiov4.10_FTransport 

Coal Type 

Heat Rate 

(Btu/ 

kWh) 

Capacity 

Penalty 

(%) 

Heat Rate 

Penalty 

(%) 

Variable 

O&M 

(mills/ 

kWh) 

Capacity (MW) 

100 300 500 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capital 

Cost 

($/kW) 

Fixed 

O&M 

($/kWyr) 

Capit

Cost 

($/kW

Bituminous 

9,000 

0.60 0.60 0.15 

188 0.8 153 0.6 139 0.6 130 

10,000 205 0.9 167 0.7 151 0.6 141 11,000 221 0.9 180 0.8 163 0.7 153 

Notes on Implementation 1. Plant specific fabric filter capital costs shown in this table are implemented in EPA Base Case v4.10_FTransport as an install fabric filters incur a total FOM charge which includes the true FOM component shown in the above table plus a capby multiplying the capital cost in the table above by a capital charge rate 11.3%, i.e.,  Total FOM = True FOM + Capital Cost FOM Adder where the FOM Adder = Capital Cost X Capital Charge Rate = Capital Cost X 11.3%. Plants that install fabric filters also incur the additional VOM costs shown in the above table. 2. Since the fabric filter costs were not endogenously modeled as a retrofit option, the capacity and heat rate penalties shonot represented in the model. 
64 

Appendix 5-4 Example Cost Calculation Worksheet for Dry Sorbent Injection (DSI) for HCl 

(and SO2) Emissions Control in EPA Base Case v4.10_FTransport 
65 
66 

Appendix 5-5 Example Cost Calculation Worksheets for Fabric Filters (A/C Ratio = 4.0 

and A/C Ratio = 6.0) in EPA Base Case v4.10_FTransport 
67 

Addendum B ─ Representation of 

State Electric Power Emission Regulations (Appendix 3-2), 

New Source Review (NSR) Settlements (Appendix 3-3), and 

State Settlements (Appendix 3-4) 

in EPA Base Case v.4.10_FTransport 

Note: The numbering of the appendices in this addendum is the same as found in the Documentation for 

EPA Base Case v.4.10 Using the Integrated Planning Model, where an earlier version of these 

appendices previously appeared. 
68

Appendices 3-2 (State Regulations), 3-3 (NSR Settlements), and 3-4 (State Settlements)

The tables of State Power Sector Regulations (Appendix 3-2), New Source Review Settlements (Appendix 

3-3), and State Settlements (Appendix 3-4) were updated to reflect changes that had occurred since the 

provisions had been incorporated in EPA Base Case v4.10. The updated tables are included below. 

************************************************************************************************************* 

Appendix 3-2 State Power Sector Regulations included in EPA Base Case v4.10_FTransport

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Alabama 

Alabama 

Administrative Code 

Chapter 335-3-8 

NOx

0.02 lbs/MMBtu annual PPMDV for combined cycle 

EGUs which commenced operation after April 1, 

2003 

2003 

Arizona Title 18, Chapter 2, 

Article 7 Hg 

90% removal of Hg content of fuel or 0.0087 

lb/GWH-hr annual reduction for all non-cogen coal 

units > 25 MW 

2017 

California CA Reclaim Market 

NOx

9.68 MTons annual cap for list of entities in 

Appendix A of "Annual RECLAIM Audit Market 

Report for the Compliance Year 2005" (304 entities) 1994 

SO2

4.292 MTons annual cap for list of entities in 

Appendix A of "Annual RECLAIM Audit Market 

Report for the Compliance Year 2005" (304 entities) 

Colorado 40 C.F.R. Part 60 Hg 

2012 & 2013: 80% reduction of Hg content of fuel or 

0.0174 lb/GW-hr annual reduction for Pawnee 

Station 1 and Rawhide Station 101 

2014 through 2016: 80% reduction of Hg content of 

fuel or 0.0174 lb/GW-hr annual reduction for all coal 

units > 25 MW 

2017 onwards: 90% reduction of Hg content of fuel 

or 0.0087 lb/GW-hr annual reduction for all coal 

units > 25 MW 

2012 

Connecticut 

Executive Order 19 

and Regulations of 

Connecticut State 

Agencies (RCSA) 

22a-174-22 

NOx

0.15 lbs/MMBtu rate limit in the winter season for all 

fossil units > 15 MW 

2003 

Executive Order 19, 

RCSA 22a-198 & 

Connecticut General 

Statues (CGS) 22a198 

SO2

0.33 lbs/MMBtu annual rate limit for all Title IV 

sources > 15 MW 

0.55 lbs/MMBtu annual rate limit for all non-Title IV 

sources > 15 MW 

Public Act No. 03-72 

& RCSA 22a-198 Hg 90% removal of Hg content of fuel or 0.0087 lb/GWhr annual reduction for all coal-fired units 2008 

Delaware 

Regulation 1148: 

Control of Stationary 

Combustion Turbine 

EGU Emissions 

NOx

0.19 lbs/MMBtu ozone season PPMDV for 

stationary, liquid fuel fired CT EGUs >1 MW 

0.39 lbs/MMBtu ozone season PPMDV for 

stationary, gas fuel fired CT EGUs >1 MW 

2009 

Regulation No. 1146: 

Electric Generating 

Unit (EGU) MultiPollutant Regulation 

NOx

0.125 lbs/MMBtu rate limit of NOx annually for all 

coal and residual-oil fired units > 25 MW 

2009 

SO2

0.26 lbs/MMBtu annual rate limit for coal and 

residual-oil fired units > 25 MW 
69

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Hg 

2012: 80% removal of Hg content of fuel or 0.0174 

lb/GW-hr annual reduction for all coal units > 25 MW 

2013 onwards: 90% removal of Hg content of fuel or 

0.0087 lb/GW-hr annual reduction for all coal units > 

25 MW 

Georgia 

Multipollutant Control 

for Electric Utility 

Steam Generating 

Units 

SCR, FGD, 

and 

Sorbent 

Injection 

Baghouse 

controls to 

be installed 

The following plants must install controls: Bowen, 

Branch, Hammond, McDonough, Scherer, Wansley, 

and Yates 

Implementation 

from 2008 

through 2015, 

depending on 

plant and control 

type 

Illinois 

Title 35, Section 

217.706 NOx

0.25 lbs/MMBtu summer season rate limit for all 

fossil units > 25 MW 2004 

Title 35, Part 225, 

Subpart B: Control of 

Hg Emissions from 

Coal Fired Electric 

Generation Units 

NOx

0.11 lbs/MMBtu annual rate limit and ozone season 

rate limit for all Dynergy and Ameren coal steam 

units > 25 MW 

2012 

SO2

2013 & 2014: 0.33 lbs/MMBtu annual rate limit for all 

Dynergy and Ameren coal steam units > 25 MW 

2015 onwards: 0.25 lbs/MMBtu annual rate limit for 

all Dynergy and Ameren coal steam units > 25 MW 

2013 

Hg 

90% removal of Hg content of fuel or 0.08 lbs/GW-hr 

annual reduction for all Ameren and Dynergy coal 

units > 25 MW 

2015 

Title 35 Part 225; 

Subpart F: Combined 

Pollutant Standards 

NOx

0.11 lbs/MMBtu ozone season and annual rate limit 

for all specified Midwest Gen coal steam units 2012 

SO2

0.44 lbs/MMBtu annual rate limit in 2013, decreasing 

annually to 0.11 lbs/MMBtu in 2019 for all specified 

Midwest Gen coal steam units 

2013 

Hg 

90% removal of Hg content of fuel or 0.08 lbs/GWh 

annual reduction for all specified Midwest Gen coal 

steam units 

2015 

Kansas 

NOx Emission 

Reduction Rule, 

K.A.R. 28-19-713a. 

NOx

0.20 lbs/MMBtu annual rate limit for Quindaro Unit 2 

and 0.26 lbs/MMBtu annual rate limit for Nearman 

Unit 1. 

2012 

Louisiana 

Title 33 Part III - 

Chapter 22, Control of 

Emissions of Nitrogen 

Oxides 

SO2

1.2 lbs/MMBtu ozone season PPMDV for all single 

point sources that emit or have the potential to emit 

5 tons or more of SO2 into the atmosphere 

2005 

Title 33 Part III - 

Chapter 15, Emission 

Standards for Sulfur 

Dioxide 

NOx

Various annual rate limits depending on plant and 

fuel type for facilities within the Baton Rouge 

Nonattainment Area that collectively have the 

potential to emit 25 tons or more per year of NOx or 

facilities within the Region of Influence that 

collectively have the potential to emit 50 tons or 

more per year of NOx 

2005 

Maine 

Chapter 145 NOx

Control Program NOx

0.22 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW built before 1995 with a heat input 

capacity < 750 MMBtu/hr 

0.15 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW built before 1995 with a heat input 

capacity > 750 MMBtu/hr 

0.20 lbs/MMBtu annual rate limit for all fossil fuel 

fired indirect heat exchangers, primary boilers, and 

resource recovery units with heat input capacity > 

250 MMBtu/hr 

2005 

Statue 585-B Title 38, 

Chapter 4: Protection 

and Improvement of 

Air 

Hg 25 lbs annual cap for any facility including EGUs 2010 
70

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Maryland Maryland Healthy Air 

Act 

NOx

3.6 MTons summer cap and 8.3 MTons annual cap 

for Mirant coal units 

0.5 MTons summer cap and 1.4 MTons annual cap 

for Allegheny coal units 

3.6 MTons summer cap and 8.03 MTons annual cap 

for Constellation coal units. 

SO2 2009 

2009 through 2012: 23.4 MTons annual cap for 

Constellation coal units, 24.2 MTons annual cap for 

Mirant Coal units, and 4.6 MTons annual cap for 

Allegheny coal units. 

2013 onwards: 17.9 MTons annual cap for 

Constellation coal units, 18.5 MTons annual cap for 

Mirant Coal units, and 4.6 MTons annual cap for 

Allegheny coal units. 

Hg 

2010 through 2012: 80% removal of Hg content of 

fuel for Mirant, Allegheny, and Constellation coal 

steam units 

2013 onwards: 90% removal of Hg content of fuel 

for Mirant, Allegheny, and Constellation coal steam 

units 

Massachusett

s 310 CMR 7.29 

NOx

1.5 lbs/MWh annual GPS for Bayton Point, Mystic 

Generating Station, Somerset Station, Mount Tom, 

Canal, and Salem Harbor 

2006 

SO2

3.0 lbs/MWh annual GPS for Bayton Point, Mystic 

Generating Station, Somerset Station, Mount Tom, 

Canal, and Salem Harbor 

Hg 

2012: 85% removal of Hg content of fuel or 

0.00000625 lbs/MWh annual GPS for Brayton Point, 

Mystic Generating Station, Somerset Station, Mount 

Tom, Canal, and Salem Harbor 

2013 onwards: 95% removal of Hg content of fuel or 

0.00000250 lbs/MWh annual GPS for Brayton Point, 

Mystic Generating Station, Somerset Station, Mount 

Tom, Canal, and Salem Harbor 

Michigan 

Part 15. Emission 

Limitations and 

Prohibitions - Mercury 

Hg 90% removal of Hg content of fuel annually for all 

coal units > 25 MW 2015 

Minnesota 

Minnesota Hg 

Emission Reduction 

Act 

Hg 90% removal of Hg content of fuel annually for all 

coal units > 250 MW 2008 

Missouri 10 CSR 10-6.350 NOx

0.25 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW in the following counties: Bollinger, 

Butler, Cape Girardeau, Carter, Clark, Crawford, 

Dent, Dunklin, Gasconade, Iron, Lewis, Lincoln, 

Madison, Marion, Mississippi, Montgomery, New 

Madrid, Oregon, Pemiscot, Perry, Phelps, Pike, 

Ralls, Reynolds, Ripley, St. Charles, St. Francois, 

Ste. Genevieve, Scott, Shannon, Stoddard, Warren, 

Washington and Wayne 

0.18 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW the following counties: City of St. 

Louis, Franklin, Jefferson, and St. Louis 

0.35 lbs/MMBtu annual rate limit for all fossil fuel 

units > 25 MW in the following counties: Buchanan, 

Jackson, Jasper, Randolph, and any other county 

not listed 

2004 

Montana 

Montana Mercury 

Rule Adopted 

10/16/06 

Hg 

0.90 lbs/TBtu annual rate limit for all non-lignite coal 

units 

1.50 lbs/TBtu annual rate limit for all lignite coal 

units 

2010 

New 

Hampshire RSA 125-O: 11-18 Hg 

80% reduction of aggregated Hg content of the coal 

burned at the facilities for Merrimack Units 1 & 2 and 

Schiller Units 4, 5, & 6 

2012 
71

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

ENV-A2900 Multiple 

pollutant annual 

budget trading and 

banking program 

NOx

2.90 MTons summer cap for all fossil steam units > 

250 MMBtu/hr operated at any time in 1990 and all 

new units > 15 MW 

3.64 MTons annual cap for Merrimack 1 & 2, 

Newington 1, and Schiller 4 through 6 

2007 

SO2

7.29 MTons annual cap for Merrimack 1 & 2, 

Newington 1, and Schiller 4 through 6 

New Jersey 

N.J.A.C. 7:27-27.5, 

27.6, 27.7, and 27.8 Hg 

90% removal of Hg content of fuel annually for all 

coal-fired units 

95% removal of Hg content of fuel annually for all 

MSW incinerator units 

2007 

N.J. A. C. Title 7, 

Chapter 27, 

Subchapter 19, Table 

1 

NOx

2009 - 2012 annual rate limits in lbs/MMBtu for the 

following technologies: 

Coal Boilers (Wet Bottom) - 1.0 for tangential and 

wall-fired, 0.60 for cyclone-fired 

Coal Boilers (Dry Bottom) - 0.38 for tangential, 0.45 

for wall-fired, 0.55 for cyclone-fired 

Oil and/or Gas or Gas only: 0.20 for tangential, 0.28 

for wall-fired, 0.43 for cyclone-fired 

2013 & 2014 annual rate limits in lbs/MWh for the 

following technologies: 

All Coal Boilers: 1.50 for all 

Oil and/or Gas: 2.0 for tangential, 2.80 for wall-fired, 

4.30 for cyclone-fired 

Gas only: 2.0 for tangential and wall-fired, 4.30 for 

cyclone-fired 

2015 onward annual rate limits in lbs/MWh for the 

following technologies: 

All Coal Boilers: 1.50 for all 

Oil and/or Gas: 2.0 for fuel heavier than No. 2 fuel 

oil, 1.0 for No. 2 and lighter fuel oil 

Gas only: 1.0 for all 

2009 

N.J. A. C. Title 7, 

Chapter 27, 

Subchapter 19, Table 

4 

NOx

2.2 lbs/MWh annual GPS for gas-burning simple 

cycle combustion turbine units 

3.0 lbs/MWh annual GPS for oil-burning simple 

cycle combustion turbine units 

1.3 lbs/MWh annual GPS for gas-burning combined 

cycle CT or regenerative cycle CT units 

2.0 lbs/MWh annual GPS for oil-burning combined 

cycle CT or regenerative cycle CT units 

2007 

New York 

Part 237 NOx

39.91 MTons non-ozone season cap for fossil fuel 

units > 25 MW 2004 

Part 238 SO2

131.36 MTons annual cap for fossil fuel units > 25 

MW 2005 

Mercury Reduction 

Program for CoalFired Electric Utility 

Steam Generating 

Units 

Hg 

786 lbs annual cap through 2014 for all coal fired 

boiler or CT units >25 MW after Nov. 15, 1990. 

0.60 lbs/TBtu annual rate limit for all coal units > 25 

MW developed after Nov.15 1990 

2010 

North Carolina 

NC Clean 

Smokestacks Act: 

Statute 143-215.107D 

NOx

25 MTons annual cap for Progress Energy coal 

plants > 25 MW and 31 MTons annual cap for Duke 

Energy coal plants > 25 MW 

2007 

SO2

2012: 100 MTons annual cap for Progress Energy 

coal plants > 25 MW and 150 MTons annual cap for 

Duke Energy coal plants > 25 MW 

2013 onwards: 50 MTons annual cap for Progress 

Energy coal plants > 25 MW and 80 MTons annual 

cap for Duke Energy coal plants > 25 MW 

2009 

Oregon 

Oregon Administrative 

Rules, Chapter 345, 

Division 24 

CO2

675 lbs/MWh annual rate limit for new combustion 

turbines burning natural gas with a CF >75% and all 

new non-base load plants (with a CE <= 75%) 

emitting CO2

1997 
72

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Oregon Utility 

Mercury Rule - 

Existing Units 

Hg 90% removal of Hg content of fuel reduction or 0.6 

lbs/TBtu limitation for all existing coal units >25 MW 2012 

Oregon Utility 

Mercury Rule - 

Potential Units 

Hg 25 lbs rate limit for all potential coal units > 25 MW 2009 

Pacific 

Northwest 

Washington State 

House Bill 3141 CO2

$1.45/Mton cost (2004$) for all new fossil-fuel power 

plant 2004 

Texas 

Senate Bill 7 Chapter 

101 

SO2

273.95 MTons cap of SO2 for all grandfathered units 

built before 1971 in East Texas Region 

2003 

NOx

Annual cap for all grandfathered units built before 

1971 in MTons: 84.48 in East Texas, 18.10 in West 

Texas, 1.06 in El Paso Region 

Chapter 117 NOx

East and Central Texas annual rate limits in 

lbs/MMBtu for units that came online before 1996: 

Gas fired units: 0.14 

Coal fired units: 0.165 

Stationary gas turbines: 0.14 

2007 

Dallas/Fort Worth Area annual rate limit for utility 

boilers, auxiliary steam boilers, stationary gas 

turbines, and duct burners used in an electric power 

generating system except for CT and CC units 

online after 1992: 

0.033 lbs/MMBtu or 0.50 lbs/MWh output or 0.0033 

lbs/MMBtu on system wide heat input weighted 

average for large utility systems 

0.06 lbs/MMBtu for small utility systems 

Houston/Galveston region annual Cap and Trade 

(MECT) for all fossil units: 

17.57 MTons 

Beaumont-Port Arthur region annual rate limits for 

utility boilers, auxiliary steam boilers, stationary gas 

turbines, and duct burners used in an electric power 

generating system: 0.10 lbs/MMBtu 

Utah 

R307-424 Permits: 

Mercury 

Requirements for 

Electric Generating 

Units 

Hg 90% removal of Hg content of fuel annually for all 

coal units > 25 MW 2013 

Wisconsin NR 428 Wisconsin 

Administration Code NOx

Annual rate limits in lbs/MMBtu for coal fired boilers 

> 1,000 MMBtu/hr : 

Wall fired, tangential fired, cyclone fired, and 

fluidized bed: 2009: 0.15, 2013 onwards: 0.10 

Arch fired: 2009 onwards: 0.18 

Annual rate limits in lbs/MMBtu for coal fired boilers 2009 

between 500 and 1,000 MMBtu/hr: 

Wall fired: 2009: 0.20; 2013 onwards: 0.17 in 2013 

Tangential fired: 2009 onwards: 0.15 

Cyclone fired: 2009: 0.20; 2013 onwards: 0.15 

Fluidized bed: 2009: 0.15; 2013 onwards: 0.10 

Arch fired: 2009 onwards: 0.18 
73

State/Region Bill Emission 

Type Emission Specifications Implementation Status 

Annual rate limits for CTs in lbs/MMBtu: 

Natural gas CTs > 50 MW: 0.11 

Distillate oil CTs > 50 MW: 0.28 

Biologically derived fuel CTs > 50 MW: 0.15 

Natural gas CTs between 25 and 49 MW: 0.19 

Distillate oil CTs between 25 and 49 MW: 0.41 

Biologically derived fuel CTs between 25 and 49 

MW: 0.15 

Annual rate limits for CCs in lbs/MMBtu: 

Natural gas CCs > 25 MW: 0.04 

Distillate oil CCs > 25 MW: 0.18 

Biologically derived fuel CCs > 25 MWs: 0.15 

Natural gas CCs between 10 and 24 MW: 0.19 

Chapter NR 446. 

Control of Mercury 

Emissions 

Hg 

2012 through 2014: 40% reduction in total Hg 

emissions for all coal-fired units in electric utilities 

with annual Hg emissions > 100 lbs 

2015 onwards: 90% removal of Hg content of fuel or 

0.0080 lbs/GW-hr reduction in coal fired EGUs > 

150 MW 

80% removal of Hg content of fuel or 0.0080 

lbs/GW-hr reduction in coal fired EGUs > 25 MW 

2010 

 

Notes:

 

Updates to the EPA Base Case v4.10_FTransport from EPA Base Case 4.10 include the following: 

1) An update of the modeling of SO2 rate limits in Connecticut 

2) An update of the modeling of the effective dates of various controls on units in Georgia 

3) Addition of two Kansas State Law unit-specific constraints 

4) An update of the modeling of NOx rate limits in Louisiana 

5) An update of the modeling of the NOx annual and summer caps and SO2 annual cap in Maryland 

6) An update of the modeling of the NOx rate limits in New Jersey 
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Alabama Power

James H. Miller Alabama Units 3 & 4

Install and 

operate FGD 

continuously

95% 12/31/11

Operate 

existing SCR 

continuously

0.1 05/01/08 0.03 12/31/06

Within 45 days of settlement entry, APC must retire 7,538 SO2 

emission allowances. 

AsoePe

eaoA

Minnkota Power Cooperative 

Unit 1

Install and 

continuously 

operate FGD

95% if wet 

FGD, 90% if 

dry

12/31/11

Install and 

continuously 

operate Overfire AIR, or 

equivalent 

technology 

with emission 

rate < .36

0.36 12/31/09

0.03 if wet 

FGD, .015 

if dry FGD

Unit 2

Design, 

upgrade, and 

continuously 

operate FGD

90% 12/31/10

Install and 

continuously 

operate overfire AIR, or 

equivalent 

technology 

with emission 

rate < .36

0.36 12/31/07 0.03 Before 2008

SIGECO

Unit 1

Repower to 

natural gas 

(or retire)

12/31/06

Unit 2

Improve and continuously 

operate 

existing FGD 

(shared by 

Units 2 and 3)

95% 06/30/04

Unit 3

Improve and continuously 

operate 

existing FGD 

(shared by 

Units 2 and 3)

95% 06/30/04

Operate 

Existing SCR 

Continuously

0.1 09/01/03

Install and 

continuously 

operate a 

Baghouse

0.015 06/30/07

PSEG FOSSIL

Bergen New Jersey Unit 2

Repower to 

combined 

cycle

12/31/02

Plant will surrender 4,346 allowances for each year 2012 – 2015, 8,693 allowances for years 2016 –2018, 12,170 allowances for year 2019, and 14,886 allowances/year thereafter if Units 1 – 3 are operational by 12/31/2015. If only Units 1 and 2 are operational by12/31/2015, the plant shall retire 17,886 units in 2020 and thereafter. The provision 

Appendix 3-3 New Source Review (NSR) Settlements in EPA Base Case v.4.10_FTransport (05-16-11)

The provision did not specify an amount of SO2 allowances 

to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired.

Mnt

aaUtoasattsdctr

Unit

Indiana

Company and 

Plant

Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Milton R. Young

FB Culley

Minnesota

Beginning 1/01/2006, Minnkota shall not emit more than 31,000 tons of SO2/year, no more than 26,000 tons beginning 2011, no more than 11,500 tons beginning 1/01/2012. If Unit 3 is not operational by 12/31/2015, then beginning 

74
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Hudson New Jersey Unit 2

Install Dry 

FGD (or 

approved alt. 

technology) 

and 

continually 

operate

0.15 12/31/06

Install SCR (or 

approved tech) 

and continually 

operate

0.1 05/01/07

Install 

Baghouse (or 

approved 

technology)

0.015 12/31/06

Mercer New Jersey Units 1 & 2

Install Dry 

FGD (or 

approved alt. 

technology) 

and 

continually 

operate

0.15 12/31/10

Install SCR (or 

approved tech) 

and continually 

operate

0.13 05/01/06

TECO

Units 1 & 2

Existing 

Scrubber 

(shared by 

Units 1 & 2)

95% (95% or 

.25)

09/1/00 

(01/01/13) Install SCR 0.1 05/01/09

Unit 3

Existing 

Scrubber 

(shared by 

Units 3 & 4)

93% if Units 3 

& 4 are 

operating

2000 

(01/01/10) Install SCR 0.1 05/01/09

Unit 4

Existing 

Scrubber 

(shared by 

Units 3 & 4)

93% if Units 3 

& 4 are 

operating

06/22/05 Install SCR 0.1 07/01/07

Gannon Florida Six units

Retire all six 

coal units and 

repower at 

least 550 MW 

of coal 

capacity to 

natural gas

12/31/04

WEPCO

Units 1 – 4

Retire or 

install SO2 

and NOx 

controls

12/31/12

Install and 

continuously 

operate FGD 

(or approved 

equiv. tech)

95% or 0.1 12/31/12

Install SCR (or 

approved tech) 

and continually 

operate

0.1 12/31/12

Units 5 & 6

Install and 

operate low 

NOx burners

12/31/03

Units 7 & 8

Operate 

existing low 

NOx burners

12/31/05 Install Baghouse

Unit 9

Operate 

existing low 

NOx burners

12/31/06 Install Baghouse

1

Install and 

continuously 

operate FGD 

(or approved 

control tech)

95% or 0.1 12/31/06

Install and 

continuously 

operate SCR 

(or approved 

tech)

0.1 12/31/06

2

Install and 

continuously 

operate FGD 

(or approved 

control tech)

95% or 0.1 12/31/07

Install and 

continuously 

operate SCR 

(or approved 

tech)

0.1 12/31/03

Presque Isle

The provision 

did not specify 

an amount of 

SO2 allowances 

to be 

surrendered. It 

only provided 

h

Pleasant Prairie Wisconsin

WEPCO shall comply with the following system wide average NOx emission rates and total NOx tonnage permissible: by 1/1/2005 an emission rate of 0.27 and 31,500 tons, by 1/1/2007 an emission rate of 0.19 and 23,400 tons, and 

of 0.17 and 17, 400 tons. For SO2 emissions, WEPCO will comply with: by 1/1/2005 an emission rate of 0.76 and 86,900 tons, by 1/1/2007 an emission rate of 0.61 and 74,400 tons, by 1/1/2008 an emission rate of 0.45 and 55,400 

emission rate of 0.32 and 33,300 tons.

Big Bend

The provision 

did not specify 

an amount of 

SO2 allowances 

to be 

surrendered. It 

only provided 

that excess 

allowances 

resulting from 

compliance with 

NSR settlement provisions must 

be retired.

Wisconsin

Florida

did not specify an amount of SO2 allowances 

to be surrendered. It only provided that excess allowances resulting from compliance with NSR settlement provisions must be retired.

75
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Units 5 & 6

Install and 

continuously 

operate FGD 

(or approved 

control tech)

95% or 0.1 12/31/12

Install and 

continuously 

operate SCR 

(or approved 

tech)

0.1 12/31/12

Unit 7

Install and 

continuously 

operate FGD 

(or approved 

control tech)

95% or 0.1 12/31/12

Install and 

continuously 

operate SCR 

(or approved 

tech)

0.1 12/31/12

Unit 8

Install and 

continuously 

operate FGD 

(or approved 

control tech)

95% or 0.1 12/31/12

Install and 

continuously 

operate SCR 

(or approved 

tech)

0.1 12/31/12

Port Washington Wisconsin Units 1 – 4 Retire

12/31/04 for 

Units 1 – 3. 

Unit 4 by 

entry of 

consent 

decree

Valley Wisconsin Boilers 1 – 4

Operate 

existing low 

NOx burner

30 days after 

entry of consent 

decree

VEPCO

Mount Storm West Virginia Units 1 – 3 Construct or improve FGD 95% or 0.15 01/01/05 Install and continuously operate SCR 0.11 01/01/08

Unit 4

Install and 

continuously 

operate SCR

0.1 01/01/13

Unit 5 Construct or improve FGD 95% or 0.13 10/12/12 Install and continuously operate SCR 0.1 01/01/12Unit 6 Construct or improve FGD 95% or 0.13 01/01/10 Install and continuously operate SCR 0.1 01/01/11

Chesapeake 

Energy Virginia Units 3 & 4

Install and 

continuously 

operate SCR

0.1 01/01/13

Clover Virginia Units 1 & 2 Improve FGD 95% or 0.13 09/01/03

Possum Point Virginia Units 3 & 4

Retire and 

repower to 

natural gas

05/02/03

Santee Cooper

Unit 1

Upgrade and 

continuously 

operate FGD

95% 06/30/06

Install and 

continuously 

operate SCR

0.1 05/31/04

Unit 2

Upgrade and 

continuously 

operate FGD

87% 06/30/06

Install and 

Continuously 

operate SCR

0.11/0.1 05/31/04 and 05/31/07

Unit 1

Install and 

continuously 

operate FGD

95% 12/31/08

Install and 

continuously 

operate SCR

0.11/0.1 11/30/04 and 11/30/04

Unit 2

Install and 

continuously 

operate FGD 

95% 12/31/08

Install and 

continuously 

operate SCR

0.12 11/30/04

Unit 3

Upgrade and 

continuously 

operate 

existing FGD

90% 12/31/08

Install and 

continuously 

operate SCR

0.14/0.12 11/30/2005 and 11/30/08

that excess 

allowances 

resulting from 

compliance with 

NSR settlement provisions must 

be retired.

Oak Creek Wisconsin

The provision 

did not specify 

an amount of 

SO2 allowances 

to be 

surrendered. It 

only provided

Cross

On or before 

March 31 of 

every year 

beginning in 

2013 and 

continuing thereafter, 

VEPCO shall 

surrender 

45,000 SO2 

allowances.

Winyah

South CarolinaSouth Carolina

Virginia

Chesterfield

The Total Permissible NOx Emissions (in tons) from VEPCO system are: 104,000 in 2003, 95,000 in 2004, 90,000 in 2005, 83,000 in 2006, 81,000 in 2007, 63,000 in 2008 – 2010, 54,000 in 2011, 50,000 in 2012, and 30,250 each y1/1/2013 they will have a system wide emission rate no greater then 0.15 lb/mmBtu.Santee Cooper shall comply with the following system wide averages for NOx emission rates and combined tons for emission of: by 1/01/2005 facility shall comply with an emission rate of 0.3 and 30,000 tons, by 1/1/2007 an emissio

tons, by 1/1/2010 and emission rate of 0.15 and 20,000 tons. For SO2 emission the company shall comply with system wide averages of: by 1/1/2005 an emission rate of 0.92 and 95,000 tons, by 1/1/2007 and emission rate of 0.75 

1/1/2009 an emission rate of 0.53 and 70 tons, and by 1/1/2011 and emission rate of 0.5 and 65 tons.

76
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Unit 4

Upgrade and 

continuously 

operate 

existing FGD

90% 12/31/07

Install and 

continuously 

operate SCR

0.13/0.12 11/30/05 and 11/30/08

Unit 1

Operate low 

NOx burner or 

more stringent 

technology

06/25/04

Unit 2

Operate low 

NOx burner or 

more stringent 

technology

05/01/04

Jeffries South Carolina Units 3, 4

Operate low 

NOx burner or 

more stringent 

technology

06/25/04

Ohio Edison

Unit 1

Install Induct

Scrubber (or

approved 

equiv.

control tech)

50% removal

or 1.1 

lb/mmBtu

12/31/08

Install SNCR

(or approved

alt. tech) &

operate

continuously

0.25 10/31/07

Unit 2

Install Induct

Scrubber (or

approved 

equiv.

control tech)

50% removal

or 1.1 

lb/mmBtu

12/31/08

Operate

existing SNCR

continuously

0.25 02/15/06

Unit 3

Install Induct

Scrubber (or

approved 

equiv.

control tech)

50% removal

or 1.1 

lb/mmBtu

12/31/08

Operate low 

NOx burners 

and overfire air 

by 12/1/05; 

install SNCR

(or approved

alt. tech) &

operate

continuously 

by 12/31/07

0.25

12/01/05 

and

10/31/07

Unit 4

Install Induct

Scrubber (or

approved 

equiv.

control tech)

50% removal

or 1.1 

lb/mmBtu

06/30/09

Install SNCR

(or approved

alt. tech) &

operate

continuously

0.25 10/31/07

Unit 5

Install Flash

Dryer 

Absorber

or ECO2 (or

approved 

equiv.

control tech) &

operate

continuously

50% removal

or 1.1 

lb/mmBtu

06/29/09

Install SNCR

(or approved

alt. tech) &

Operate

Continuously

0.29 03/31/08

only provided

that excess 

allowances 

resulting from 

compliance with 

NSR settlement provisions must 

be retired.

Grainger South Carolina

W.H. Sammis 

Plant Ohio

Beginning on 

1/1/2006, Ohio 

Edison may use, 

sell or transfer 

any restricted 

SO2 only to 

satisfy the 

Operational 

Needs at the 

Sammis, Burger 

and Mansfield 

Plant, or new 

units within the 

FirstEnergy 

System that 

comply with a 

96% removal for 

SO2. For 

calendar year 

2006 through

Ohio Edison shall achieve reductions of 2,483 tons NOx between 7/1/2005 and 12/31/2010 using any combination of: 1) low sulfur coal at Burger Units 4 and 5, 2) operating SCRs currently installed at Mansfield Units 1 – 3 during the 

April, and/or 3) emitting fewer tons than the Plant-Wide Annual Cap for NOx required for the Sammis Plant. Ohio Edison must reduce 24,600 tons system-wide of SO2 by 12/31/2010.

No later than 8/11/2005, Ohio Edison shall install and operate low NOx burners on Sammis Units 1 - 7 and overfired air on Sammis Units 1,2,3,6, and 7. No later than 12/1/2005, Ohio Edison shall install advanced combustion contro

minimize NOx emissions from Sammis Units 1 – 5.

77
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Unit 6

Install FGD3 

(or

approved 

equiv.

control tech) &

operate

continuously

95% removal 

or 0.13 

lb/mmBtu

06/30/11

Install SNCR

(or approved

alt. tech) &

operate

continuously

"Minimum

Extent

Practicable"

06/30/05

Operate

Existing

ESP

Continuously

0.03 01/01/10

Unit 7

Install FGD (or

approved 

equiv.

control tech) &

operate

continuously

95% removal 

or 0.13 

lb/mmBtu

06/30/11

Operate

existing SNCR

Continuously

"Minimum

Extent

Practicable"

08/11/05

Operate

Existing

ESP

Continuously

0.03 01/01/10

Unit 1 Upgrade existing FGD 95% 12/31/05Unit 2 Upgrade existing FGD 95% 12/31/06

Unit 3 Upgrade existing FGD 95% 10/31/07

Eastlake Ohio Unit 5

Install low NOx 

burners, overfired

air and SNCR 

& operate 

continuously

"Minimize 

Emissions 

to the

Extent

Practicable"

12/31/06

Unit 4 12/31/11Unit 5 12/31/11

MirantI1,6

Unit 1Unit 2Unit 3

Install low NOx

burners (or 

more effective 

tech) &

operate 

continuously 

05/01/04

Unit 4

Install low NOx

burners (or 

more effective 

tech) &

operate 

continuously 

05/01/04

Unit 5

Install low NOx

burners (or 

more effective 

tech) &

operate 

continuously 

05/01/04

Pennsylvania

Ohio

Virginia

Potomac River 

Plant

2006 through

2017, Ohio 

Edison may 

accumulate SO2 

allowances for 

use at the 

Sammis, 

Burger, and 

Mansfield 

plants, or 

FirstEnergy 

units equipped 

with SO2 

Emission 

Control 

Standards. 

Beginning in 

2018, Ohio 

Edison shall 

surrender 

unused 

restricted SO2 

allowances.

Mansfield Plant

Repower with 

at least 80% 

biomass fuel, 

up to 20% low 

sulfur coal.

Burger

System-wide NOx Emission Annual Caps: 36,500 tons 2004; 33,840 tons 2005; 33,090 tons 2006; 28,920 tons 2007; 22,000 tons 2008; 19,650 tons 2009; 16,000 tons 2010 onward. System-wide NOx Emission Ozone Season Caps

tons 2005; 12,590 tons 2006; 10,190 tons 2007; 6,150 tons 2008 – 2009; 5,200 tons 2010 thereafter. Beginning on 5/1/2008, and continuing for each and every Ozone Season thereafter, the Mirant System shall not exceed a System

Emission Rate of 0.150 lb/mmBtu NOx.

78
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Unit 1

Install SCR 

(or approved 

alt. tech) & 

operate 

continuously 

0.1 05/01/07

Unit 2

Install SCR 

(or approved 

alt. tech) & 

operate 

continuously 

0.1 05/01/08

Unit 1

Install and 

continuously 

operate FGD 

(or equiv. 

technology)

95% 06/01/10

Unit 2

Install and 

continuously 

operate FGD 

(or equiv. 

technology)

95% 06/01/10

Illinois Power

Units 1 & 2

Install wet or 

dry FGD (or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

0.1 12/31/11

Operate OFA 

& existing SCR 

continuously

0.1 08/11/05

Install & 

continuously 

operate 

Baghouse

0.015 12/31/10

Unit 3

Install wet or 

dry FGD (or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

0.1 12/31/11

Operate OFA 

and/or low NOx 

burners

0.12 until 

12/30/12; 

0.1 from 

12/31/12

08/11/05 and 

12/31/12

Install & 

continuously 

operate 

Baghouse

0.015 12/31/10

Havana Illinois Unit 6

Install wet or 

dry FGD (or 

approved 

equiv. alt. 

tech) & 

operate 

continuously 

1.2 lb/mmBtu 

until 

12/30/2012; 

0.1 lb/mmBtu 

from 

12/31/2012 

onward

08/11/05 

and

12/31/12

Operate OFA 

and/or low NOx 

burners & 

operate 

existing SCR 

continuously

0.1 08/11/05

Install & 

continuously 

operate 

Baghouse, 

then install 

ESP or alt. PM 

equip

For Baghouse: 

0.015 

lb/mmBtu; 

For ESP: 

0.03 

lb/mmBtu

For 

Baghouse: 

12/31/12;

For ESP: 

12/31/05

By year end 

2008, Dynergy 

will surrender 

12,000 SO2 

emission 

allowances, by 

year end 2009 it 

will surrender 

18,000, by year 

end 2010 it will 

surrender 

24,000, any by 

year end 2011 

and each year 

thereafter it will 

surrender 

30,000 

allowances. If 

Illinois

Morgantown 

Plant

Chalk Point

For each year 

after Mirant 

commences 

FGD operation 

at Chalk Point, 

Mirant shall 

surrender the 

number of SO2 

Allowances 

equal to the 

amount by 

which the SO2 

Allowances 

allocated to the 

Units at the Chalk Point 

Plant are 

greater than the 

total amount of 

SO2 emissions 

allowed under 

this Section 

XVIII.

MarylandMaryland

Baldwin

Note: Havana Unit 6 in the Illinois Power NSR settlement refers to the affected electric generator. The provisions shown here as applying to Havana Unit 6 are represented in IPM as applying to Havana Unit 9, which is the boiler that powers generator unit #6.System-wide NOx Emission Annual Caps: 15,000 tons 2005; 14,000 tons 2006; 13,800 tons 2007 onward. System-wide SO2 Emission Annual Caps: 66,300 tons 2005 – 2006; 65,000 tons 2007; 62,000 tons 2008 – 2010; 57,000 t29,000 tons 2013 onward.

79
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Unit 1 1.2 07/27/05

Operate OFA

and/or low NOx 

burners

"Minimum

Extent

Practicable"

08/11/05

Install ESP (or 

equiv. alt. tech) 

& continuously 

operate ESPs

0.03 12/31/06

Unit 2 1.2 07/27/05

Operate OFA

and/or low NOx 

burners

"Minimum

Extent

Practicable"

08/11/05

Install ESP (or 

equiv. alt. tech) 

& continuously 

operate ESPs

0.03 12/31/06

Vermilion Illinois Units 1 & 2 1.2 01/31/07

Operate OFA

and/or low NOx 

burners

"Minimum

Extent

Practicable"

08/11/05

Install ESP (or 

equiv. alt. tech) 

& continuously 

operate ESPs

0.03 12/31/10

Wood River Illinois Units 4 & 5 1.2 07/27/05

Operate OFA

and/or low NOx 

burners

"Minimum

Extent

Practicable"

08/11/05

Install ESP (or 

equiv. alt. tech) 

& continuously 

operate ESPs

0.03 12/31/05

Kentucky Utilities Company

EW Brown 

Generating 

Station

Kentucky Unit 3 Install FGD 97% or 0.100 12/31/10

Install and 

continuously 

operate SCR 

by 12/31/2012, 

continuously 

operate low 

NOx boiler and 

OFA.

0.07 12/31/12 Continuously operate ESP 0.03 12/31/10

KU must 

surrender 

53,000 SO2 

allowances of 

2008 or earlier 

vintage by 

March 1, 2009. All surplus NOx 

allowances must 

be surrendered 

through 2020. 

a

c

Salt River Project Agricultural Improvement and Power District (SRP)

Unit 1 or 

Unit 2

Immediately 

begin 

continuous 

operation of 

existing FGDs 

on both units, 

install new 

FGD.

95% or 0.08

New FGD 

installed by 

1/1/2012

Install and 

continuously 

operate low 

NOx burner 

and SCR

0.32 prior to 

SCR 

installation, 

0.080 after

LNB by 

06/01/2009, 

SCR by 

06/01/2014

Optimization 

begins 

immediately, 

rate limit 

begins 

01/01/12 

(date of new 

FGD 

installation)

Unit 1 or 

Unit 2

Install new 

FGD 95% or 0.08 01/01/13

Install and 

continuously 

operate low 

NOx burner

0.32 06/01/11

Optimization 

begins 

immediately, 

rate limit 

begins 

01/01/13 

(date of new 

FGD 

installation)

American Electric Power

Annual Cap 

(tons) Year Annual Cap (tons) Year

Arizona

the surrendered 

allowances 

result in 

insufficient 

remaining 

allowances 

allocated to the 

units comprising 

the DMG 

system, DMG 

can request to 

surrender fewer 

SO2 allowances.

Hennepin Illinois

Coronado 

Generating 

Station

Optimization 

and continuous 

operation of 

existing ESPs.

0.03

Beginning in 

2012, all surplus 

SO2 allowances 

for both 

Coronado and 

Springerville 

Unit 4 must be 

surrendered 

through 2020. 

The allowances 

limited by this 

condition may, 

however, be 

used for 

compliance at a 

prospective 

future plant 

using BACT and 

otherwise 

specified in par. 

54 of the 

consent decree.

a

c

80
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

 450,000 2010 96,000 2009  450,000 2011 92,500 2010  420,000 2012 92,500 2011  350,000 2013 85,000 2012  340,000 2014 85,000 2013  275,000 2015 85,000 2014  260,000 2016 75,000 2015  235,000 2017 72,000 2016 and thereafter 184,000 2018  174,000 2019 and thereafter

West Virginia Sporn 1 – 4

Virginia Clinch River 1 – 3

Indiana

Tanners 

Creek 

1 – 3

West Virginia Kammer 1 – 3

Unit 1

Install and 

continuously 

operate FGD

12/31/09

Install and 

continuously 

operate SCR

01/01/08

Unit 2

Install and 

continuously 

operate FGD

12/31/10

Install and 

continuously 

operate SCR

01/01/09

Unit 3

Install and 

continuously 

operate FGD

12/31/09

Install and 

continuously 

operate SCR

01/01/08

Unit 1

Burn only coal 

with no more 

than 1.75 

lb/MMBtu 

annual 

average

Date of entry

Continuously 

operate low 

NOx burners

Date of entry

Unit 2

Install and 

continuously 

operate FGD

12/31/15

Install and 

continuously 

operate SCR

01/01/09

Amos West Virginia

Big Sandy Kentucky

At least 600MW 

from various 

units

Retire, retrofit, 

or re-power

12/31/18

Eastern System-Wide

NOx and SO2 

allowances that 

would have 

been made 

available by 

emission 

reductions 

pursuant to the 

Consent Decree 

must be 

surrendered.

u

w

l

b

s

c

81
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Unit 1

Install and 

continuously 

operate FGD

12/31/08

Install and 

continuously 

operate SCR

01/01/09 Continuously operate ESP 0.03 12/31/09

Unit 2

Install and 

continuously 

operate FGD

12/31/08

Install and 

continuously 

operate SCR

01/01/09 Continuously operate ESP 0.03 12/31/09

Unit 3

Install and 

continuously 

operate FGD

12/31/12

Install and 

continuously 

operate SCR

01/01/09

Clinch River Virginia Units 1 – 3

Plant-wide 

annual cap: 

21,700 tons 

from 2010 to 

2014, then 

16,300 after 

1/1/2015

2010 – 2014, 

2015 and 

thereafter

Continuously 

operate low 

NOx burners

Date of entry

Unit 1 Retire, retrofit, 

or re-power Date of entry

Unit 2 Retire, retrofit, 

or re-power Date of entry

Unit 3 Retire, retrofit, 

or re-power

12/31/12

Unit 4

Install and 

continuously 

operate FGD

12/31/10

Install and 

continuously 

operate SCR

12/31/10

Unit 5 Upgrade existing FGD 95% 12/31/09 Continuously operate low NOx burners Date of entry

Unit 6 Upgrade existing FGD 95% 12/31/09 Continuously operate low NOx burners Date of entryUnit 1

Install and 

continuously 

operate FGD

Date of entry

Install and 

continuously 

operate SCR

01/01/09

Unit 2

Install and 

continuously 

operate FGD

Date of entry

Install and 

continuously 

operate SCR

01/01/09

Units 

1 – 3

Units 5, 6

Burn only coal 

with no more 

than 1.75 

lb/MMBtu 

annual 

average

Date of entry

Continuously 

operate low 

NOx burners

Date of entry

Kammer West Virginia Units 1 – 3 Plant-wide annual cap: 35,000 01/01/10 Continuously operate over- fire air Date of entry

Kanawha River West Virginia Units 1, 2

Burn only coal 

with no more 

than 1.75 

lb/MMBtu 

annual 

average

Date of entry

Continuously 

operate low 

NOx burners

Date of entry

Unit 1

Install and 

continuously 

operate FGD

12/31/07

Install and 

continuously 

operate SCR

01/01/09

Unit 2

Install and 

continuously 

operate FGD

12/31/07

Install and 

continuously 

operate SCR

01/01/09

Ohio

West Virginia

OhioOhio

Virginia

Cardinal

Conesville

Gavin

Glen Lyn

Mitchell

82
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Mountaineer West Virginia Unit 1

Install and 

continuously 

operate FGD

12/31/07

Install and 

continuously 

operate SCR

01/01/08

Units 

1 – 4

Retire, retrofit, 

or re-power

12/31/15

Unit 5

Install and 

continuously 

operate FGD

12/31/15

Install and 

continuously 

operate SCR

01/01/08 Continuously operate ESP 0.03 12/31/02

Picway Ohio Unit 9

Continuously 

operate low 

NOx burners

Date of entry

Unit 1

Install and 

continuously 

operate FGD

12/31/17

Install and 

continuously 

operate SCR

12/31/17

Unit 2

Install and 

continuously 

operate FGD

12/31/19

Install and 

continuously 

operate SCR

12/31/19

Sporn West Virginia Unit 5 Retire, retrofit, or re-power 12/31/13

Units 

1 – 3

Burn only coal 

with no more 

than 1.2 

lb/MMBtu 

annual 

average

Date of entry

Continuously 

operate low 

NOx burners

Date of entry

Unit 4

Burn only coal 

with no more 

than 1.2% 

sulfur content 

annual 

average

Date of entry

Continuously 

operate overfire air Date of entry

East Kentucky Power Cooperative Inc.By 12/31/2009, EKPC shall choose whether to: 1) install and continuously operate NOx controls at Cooper 2 by 12/31/2012 and SO2 controls by 6/30/2012 or 2) retire Dale 3 and Dale 4 by 12/31/2012.

12-month 

rolling limit 

(tons)

Start of 12-

month cycle

12-month 

rolling limit 

(tons)

Start of 12-

month cycle

57,000 10/01/08 11,500 01/01/0840,000 07/01/11 8,500 01/01/13

Ohio Muskingum River

Tanners Creek Indiana

0.03

System-wide 

12-month 

rolling tonnage 

limits apply

All units must 

operate low 

NOx boilers

PM control 

devices must 

be operated 

continuously 

system-wide, 

ESPs must be 

optimized 

within 270 days 

of entry date, 

or EKPC may 

choose to 

submit a PM 

Pollution 

Control 

Upgrade 

Analysis.

System-wide

All surplus SO2 

allowances must 

be surrendered 

each year, 

beginning in 

2008.

1 year from 

entry date

u

E

u

E

Rockport Indiana

83
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

28,000 01/01/13 8,000 01/01/15

Unit 1

Install and 

continuously 

operate FGD

95% or 0.1 6/30/2011 Continuously operate SCR

0.12 for 

Unit 1 until 

01/01/2013, 

at which 

point the 

unit limit drops to 

0.1. Prior 

to 

01/01/2013, 

the 

combined 

average 

when both 

units are 

operating 

must be no 

more than 

0.1

60 days after 

entry

Unit 2

Install and 

continuously 

operate FGD 

by 10/1/2008

95% or 0.1 1/1/2009

Continuously 

operate SCR 

and OFA

0.1 for Unit 

2, 0.1 

combined 

average 

when both 

units are 

operating

60 days after 

entry

Unit 1

Install and 

continuously 

operate low 

NOx burners by 

10/31/2007

0.46 01/01/08

Unit 2

Install and 

continuously 

operate low 

NOx burners by 

10/31/2007

0.46 01/01/08

Unit 3

EKPC may 

choose to 

retire Dale 3 

and 4 in lieu 

of installing 

controls in 

Cooper 2

12/31/2012

Unit 4Unit 1 

Spurlock

EKPC must 

surrender 1,000 

NOx allowances 

immediately 

under the ARP, 

and 3,107 under 

the NOx SIP 

Call. EKPC 

must also 

surrender 

15,311 SO2 

allowances.

Dale Plant Kentucky

Kentucky

E

m

s

c

84
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Unit 2

If EKPC opts 

to install 

controls rather 

than retiring 

Dale, it must 

install and 

continuously 

operate FGD 

or equiv. 

technology

95% or 0.10

If EKPC elects 

to install 

controls, it 

must 

continuously 

operate SCR 

or install equiv. 

technology

0.08 (or 

90% if nonSCR 

technology 

is used)

12/31/12

Nevada Power CompanyBeginning 1/1/2010, combined NOx emissions from Units 5,6,7, and 8 must be no more than 360 tons per year.

Unit 5

5ppm 1-

hour 

average

12/31/08 (ULNB 

installation), 

01/30/09 (1-

hour average)

Unit 6

5ppm 1-

hour 

average

12/31/09 (ULNB 

installation), 

01/30/10 (1-

hour average)

Unit 7

5ppm 1-

hour 

average

12/31/09 (ULNB 

installation), 

01/30/10 (1-

hour average)

Unit 8

5ppm 1-

hour 

average

12/31/08 (ULNB 

installation), 

01/30/09 (1-

hour average)

Dayton Power & LightNon-EPA Settlement of 10/23/2008

Owners may 

not purchase 

any new 

catalyst with 

SO2 to SO3 

conversion 

rate greater 

than 0.5%

0.17 stationwide 30 days after entry

0.17 stationwide 60 days after entry date

82% including 

data from 

periods of 

malfunctions

7/31/09 

through 

7/30/11

Install control 

technology on 

one unit

0.10 on any 

single unit 12/31/12

0.15 stationwide 07/01/120.10 stationwide 12/31/14

PSEG FOSSIL, Amended Consent Decree of November 2006

Unit 7 Retire unit 01/01/07Unit 8 Retire unit 01/01/07

0.030 lb 

per unit

Ohio

New Jersey

after 7/31/11

Stuart 

Generating 

Station

82% including 

data from 

periods of 

malfunctions

Kearny Allowances 

allocated to 

Kearny, 

Hudson, and 

07/31/09

u

s

Install 

rigid-type 

electrodes in 

each 

unit's ESP

12/31/15

96% or 0.10 07/31/09

Station-wide

Nevada Clark Generating Station Units may only fire natural gas

Increase water 

injection 

immediately, 

then install and 

operate ultralow NOx 

burners 

(ULNBs) or 

equivalent 

technology. In 

2009, Units 5 

and 8 may not 

emit more than 

180 tons 

combined

u

n

m

Complete 

installation of 

FGDs on each 

unit.

Cooper Kentucky

85
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

0.15 12/31/10

Install SCR (or 

approved tech) 

and continually 

operate

0.1 12/31/10

Install 

Baghouse (or 

approved 

technology)

0.015 12/31/10

Annual Cap 

(tons) Year Annual Cap (tons) Year

5,547 2007 3,486 20075,270 2008 3,486 20085,270 2009 3,486 20095,270 2010 3,486 2010

Mercer New Jersey Units 1 &2

Install Dry 

FGD (or 

approved alt. 

technology) 

and 

continually 

operate

0.15 12/31/10

Install SCR (or 

approved tech) 

and continually 

operate

0.1 01/01/07

Install 

Baghouse (or 

approved 

technology)

0.015 12/31/10

Jeffrey Energy 

Center Kansas All units

Duke Energy

Units 1 & 3

Retire or 

repower as natural gas

1/1/2012

Units 2 & 4

Install Dry 

sorbent 

injection 

technology

80% 1/1/2012

Units 2 & 3Units 1 & 4

American Municipal Power

Gorsuch Station Ohio

Elected to Retire Dec 15, 

2010 (must retire by Dec 31, 

2012)

Indiana

Install Dry 

FGD (or 

approved alt. 

technology) 

and 

continually 

operate

Gallagher

Westar Energy

Units 1, 2, and 3 have a total annual limit of 6,600 tons of SO2 and an annual rate limit of 0.07 lbs/MMBtu starting 2012 Units 1, 2, and 3 must all install FGDs by 2011 and operate them continuously. FGDs must maintain a 30-Day Rolling Average Unit Removal Efficiency for SO2 of at least 97% or a 30-Day Rolling Average Unit Emission Rate for SO2 of no greater than 0.070 lb/MMBtu. 

Units 1-3 must continuously operate Low NOx Combustion Systems by 2012 and achieve and maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.180 lb/MMBtu.One of the three units must install an SCR by 2015 and operate it continuously to maintain a 30-Day Rolling Average Unit Emission Rate for NOx of no greater than 0.080 lb/MMBtu.By 2013 Westar shall elect to either (a) install a second SCR on one of the other JEC Units by 2017 or (b) meet a 0.100 lb/MMBtu PlantWide 12-Month Rolling Average Emission Rate and 9.6 MTons annual cap for NOx by 2015

Units 1, 2, and 3 must operate each ESP and FGD system continuously by 2011 and maintain a 0.030 lb/MMBtu PM Emissions Rate. Units 1 and 2’s ESPs must be rebuilt by 2014 in order to meet a 0.030 lb/MMBtu PM Emissions Rate 

,

Mercer may only 

be used for the 

operational 

needs of those 

units, and all 

surplus 

allowances must 

be surrendered. 

Within 90 days 

of amended 

Consent 

Decree, PSEG 

must surrender 

1,230 NOx 

Allowances and 

8,568 SO2 

Allowances not 

already 

allocated to or 

generated by 

the units listed 

here. Kearny 

allowances must 

be surrendered 

with the 

shutdown of 

those units.

Hudson New Jersey Unit 2

86
Allowance 

Retirement

Action Effective Date Equipment Percent Removal or Rate Effective Date Equipment Rate Effective Date Equipment Rate Effective Date Retirement 

Unit 

Company and Plant Retire/Repower SO2 control NOx Control PM or Mercury Control

Settlement Actions

State

Ratts Indiana Units 1 & 2

Install & 

continually 

operate 

SNCRS

0.25 12/31/2011

Unit 1

Continusly run 

current FGD 

for 90% 

removal and 

update FGD 

for 98% 

removal by 

2012

98% 2012

Unit 2

Continusly run 

current FGD 

for 90% 

removal and 

update FGD 

for 98% 

removal by 

2014

98% 2014

Allen Steam Plant Tennessee Units 1 - 3 Install FGD 12/31/2015 Operate SCR In NEEDS

Bull Run Tennessee Unit 1 Operate Wet FGD In NEEDS Operate SCR In NEEDS

Units 1 - 4 Install FGD 6/30/2016 Install SCR 6/30/2016

Unit 5 Install FGD 12/31/2015 Operate SCR In NEEDS

Cumberland Tennessee Units 1 & 2 Operate Wet FGD In NEEDS Operate SCR In NEEDS

Gallatin Tennessee Units 1 - 4 Install FGD 12/31/2017 Install SCR 12/31/2017

Units 1 & 2 Retire 12/31/2012Units 3 & 4 Install FGD 12/31/2015 Install SCR 12/31/2015

Units 1 - 4 Retire 12/31/2017Units 5 - 8 Retire 12/31/2018

Units 9 & 10 Retire 12/31/2019

Kingston Kentucky Units 1 - 9 Operate Wet FGD In NEEDS Operate SCR In NEEDS

Units 1 & 2 Upgrade FGD 93% 12/31/2012 Operate SCR In NEEDS

Unit 3 Operate Wet FGD In NEEDS Operate SCR In NEEDS

Shawnee Kentucky Units 1 & 4 Install FGD 12/31/2017 Install SCR 12/31/2017

Units 1 & 2 Retire 7/31/2013Units 3 & 4 Retire 7/31/2014Units 5 & 6 Retire 7/31/2015Units 7 & 8 Operate Wet FGD In NEEDS Operate SCR In NEEDS

Notes:

Widows Creek Alabama

Paradise Kentucky

Tennessee

John Sevier Tennessee

Johnsonville

Colbert Alabama

Merom Indiana

Continuously 

operate 

existing SCRs

Continuously operate ESP

0.12

Continuously operate ESP and achieve 

PM rate no greater than 0.007 by 6/1/12

Annually surre

allowances that 

order to meet 

Continuously operate ESP and achieve 

PM rate no greater than 0.007 by 6/1/13

10) EPA included in EPA Base Case the requirements of the settlements as they existed on January 1, 2011. 11) Some of the NSR settlements require the retirement of SO2 allowances. For the Base Case, EPA estimate the amount of allowances to be retired from these settlements and adjusted the total Title IV allowances accordingly.6) For units for which an FGD is modeled as an emissions constraint in EPA Base Case, EPA used the assumptions on removal efficiencies that are shown in the latest emission control technologies documentation7) For units for which an FGD is hardwired in EPA Base Case, unless the type of FGD is specified in the settlement, EPA modeling assumes the most cost effective FGD (wet or dry) and a corresponding 95% removal efficiency for w8) For units for which an SCR is modeled as an emissions constraint or is hardwired in EPA Base Case, EPA assumed an emissions rate equal to 10% of the unit's uncontrolled rate, with a floor of .06 lb/MMBtu or used the emission 9) The applicable low NOx burner reduction efficiencies are shown in Table A 3-1:3 in the Base Case documentation materials.2) This summary table describes New Source Review settlement actions as they are represented in EPA Base Case. The settlement actions are simplified for representation in the model. This table is not intended to be a comprehagreements.3) Settlement actions for which the required emission limits will be effective by the time of the first mapped run year (before 1/1/2012) are built into the database of units used in EPA Base Case ("hardwired"). However, future actionemission rates in EPA Base Case, allowing the modeled economic situation to dictate whether and when a unit would opt to install controls versus retire.4) Some control installations that are required by these NSR settlements have already been taken by the affected companies, even if deadlines specified in their settlement haven't occurred yet. Any controls that are already in place 5) If a settlement agreement requires installation of PM controls, then the controls are shown in this table and reflected in EPA Base Case. If settlement requires optimization or upgrade of existing PM controls, those actions are not 

Hoosier Energy Rural Electric Cooperative1) Updates to the EPA Base Case 4.10_FTransport from EPA Base Case 4.10 include the additions of the American Municipal Power settlement, the Hoosier Energy Rural Electric Cooperative settlement, a modification to the contro

settlement, and an update to the SO2 emission modeling on Jeffrey Energy Center as part of the Westar settlement.

Tennessee Valley Authority

87
88

Appendix 3-4 State Settlements in EPA Base Case v4.10_FTransport

Company and 

Plant State Unit 

State Enforcement Actions 

Retire/Repower SO2 control NOx Control PM Control 

Actio

n 

Effective 

Date Equipment 

Percent 

Removal or 

Rate 

Effective 

Date Equipment Rate Effective Date Equipment Rate Effec

Da

AES 

Greenidge New York Unit 4 Install FGD 90% 09/01/07 Install SCR 0.15 09/01/07 Unit 3 Install BACT 12/31/09 Install BACT 12/31/09 

Westover New York Unit 8 90% 12/31/10 Install SCR 0.15 12/31/10 Unit 7 Install BACT 12/31/09 Install BACT 12/31/09 

Hickling New York Units 1 & 2 Install BACT 05/01/07 Install BACT 05/01/07 

Jennison New York Units 1 & 2 Install BACT 05/01/07 Install BACT 05/01/07 

Niagara Mohawk Power NRG shall comply with the below annual tonnage limitations for its Huntley and Dunkirk Stations: 2005 is 59,537 tons of SO2 and 10,777 tons of NOx, 2006 is 34,230 of SO2 and 6,772 of NOx, 2007 is 30tons of SO2

Huntley New York Units 63 – 66 Retire Before 2008 

Public Service Co. of NM 

San Juan New Mexico 

Unit 1 

State-of-theart 

technology 

90% 

10/31/08 

State-of-theart 

technology 

0.3 

10/31/08 

Operate 

Baghouse and 

demister 

technology 

0.015 

12/3

Unit 2 03/31/09 03/31/09 12/3Unit 3 04/30/08 04/30/08 04/30Unit 4 10/31/07 10/31/07 10/3

Public Service Co of Colorado 

Comanche Colora do 

Units 1 & 

2 

Install and 

operate 

FGD 

0.1 

lb/mmBtu 

combined 

average 

07/01/09 

Install lowNOx

emission 

controls 

0.15 

lb/mmBtu 

combined 

average 

07/01/09 

Unit 3 

Install and 

operate 

FGD 

0.1 

lb/mmBtu 

Install and 

operate 

SCR 

0.08 

Install and 

operate a fabric 

filter dust 

collection 

system 

0.013 

Rochester Gas & Electric 

Russell Plant New York Units 1 – 4 Retire all units 

Mirant New York 

Lovett Plant New York Unit 1 Retire 05/07/07 Unit 2 Retire 04/30/08 

Note: The TVA settlement with North Carolina was removed from this table to reflect the July 26, 2010 ruling by the U.S. Court of Appeals, Fourth Circuit Court reversing the settlement.